Attached files
| file | filename |
|---|---|
| EX-23.6 - EX-23.6 - JP Energy Partners LP | a2221504zex-23_6.htm |
| EX-10.3 - EX-10.3 - JP Energy Partners LP | a2221504zex-10_3.htm |
| EX-10.9 - EX-10.9 - JP Energy Partners LP | a2221504zex-10_9.htm |
| EX-23.12 - EX-23.12 - JP Energy Partners LP | a2221504zex-23_12.htm |
| EX-23.4 - EX-23.4 - JP Energy Partners LP | a2221504zex-23_4.htm |
| EX-23.3 - EX-23.3 - JP Energy Partners LP | a2221504zex-23_3.htm |
| EX-8.1 - EX-8.1 - JP Energy Partners LP | a2221504zex-8_1.htm |
| EX-23.7 - EX-23.7 - JP Energy Partners LP | a2221504zex-23_7.htm |
| EX-5.1 - EX-5.1 - JP Energy Partners LP | a2221504zex-5_1.htm |
| EX-23.5 - EX-23.5 - JP Energy Partners LP | a2221504zex-23_5.htm |
| EX-23.2 - EX-23.2 - JP Energy Partners LP | a2221504zex-23_2.htm |
| EX-23.1 - EX-23.1 - JP Energy Partners LP | a2221504zex-23_1.htm |
Use these links to rapidly review the document
TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 22, 2014
Registration No. 333-195787
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 3
to
Form S-1
REGISTRATION STATEMENT UNDER THE
THE SECURITIES ACT OF 1933
JP Energy Partners LP
(Exact name of Registrant as Specified in Its Charter)
| Delaware (State or Other Jurisdiction of Incorporation or Organization) |
4610 (Primary Standard Industrial Classification Code Number) |
27-2504700 (I.R.S. Employer Identification Number) |
600 East Las Colinas Boulevard
Suite 2000
Irving, Texas 75039
(972) 444-0300
(Address, Including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)
J. Patrick Barley
President and Chief Executive Officer
600 East Las Colinas Boulevard
Suite 2000
Irving, Texas 75039
(972) 444-0300
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)
| Copies to: | ||||
Ryan J. Maierson John M. Greer Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400 |
William J. Cooper Andrews Kurth LLP 1350 I St. NW, Suite 110 Washington, DC 20005 (202) 662-2700 |
Jon W. Daly Andrews Kurth LLP 600 Travis Street, Suite 4200 Houston, Texas 77002 (713) 220-4200 |
||
Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer o | Accelerated filer o | Non-accelerated filer ý (Do not check if a smaller reporting company) |
Smaller reporting company o |
CALCULATION OF REGISTRATION FEE
|
||||||||
| Title of Each Class of Securities To Be Registered |
Amount to be Registered(1) |
Proposed Maximum Aggregate Offering Per Unit(2) |
Proposed Maximum Aggregate Offering Price(1)(2) |
Amount of Registration Fees(3) |
||||
|---|---|---|---|---|---|---|---|---|
Common units representing limited partner interests |
15,812,500 | $21.00 | $332,062,500 | $42,770 | ||||
|
||||||||
- (1)
- Estimated
pursuant to Rule 457(a) under the Securities Act of 1933, as amended. includes 2,062,500 additional common units that the underwriters have
the option to purchase.
- (2)
- Estimated
solely for the purpose of calculating the registration fee.
- (3)
- The Registrant previously paid $25,760 of the total registration fee in connection with the previous filing of the Registration Statement on May 8, 2014.
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
Subject to Completion, dated September 22, 2014
PROSPECTUS
JP Energy Partners LP
13,750,000 Common Units
Representing Limited Partner Interests
This is an initial public offering of common units representing limited partner interests of JP Energy Partners LP. We are offering 13,750,000 common units in this offering. No public market currently exists for our common units. We have been approved to list our common units on the New York Stock Exchange under the symbol "JPEP." We anticipate that the initial public offering price will be between $19.00 and $21.00 per common unit.
As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both United States citizens and subject to United States federal income taxation on our income. If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.
Investing in our common units involves risks. Please read "Risk Factors" beginning on page 22 of this prospectus. These risks include the following:
- •
- We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and
expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.
- •
- On a pro forma basis we would not have had sufficient distributable cash flow to pay the full minimum quarterly
distribution on all of our units for the year ended December 31, 2013 or for the twelve months ended June 30, 2014, with shortfalls of $23.1 million for the year ended
December 31, 2013 and $33.0 million for the twelve months ended June 30, 2014.
- •
- We face intense competition in all of our business segments. Competitors that are able to supply our customers with similar
services or products at a lower price could reduce our revenues.
- •
- Our general partner and its affiliates, including Lonestar Midstream Holdings, LLC, JP Energy Development LP,
ArcLight Energy Partners Fund V, L.P. and ArcLight Capital Partners, LLC, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their
own interests to our detriment and that of our unitholders.
- •
- Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
- •
- Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
- •
- Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service
were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level
taxation, then our distributable cash flow would be substantially reduced.
- •
- Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
| |
Per Common Unit | Total | |||||
|---|---|---|---|---|---|---|---|
Price to the public |
$ | $ | |||||
Underwriting discounts and commissions(1) |
$ | $ | |||||
Proceeds to us (before expenses) |
$ | $ | |||||
- (1)
- Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering payable by us to Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated. Please read "Underwriting."
We have granted to the underwriters a 30-day option to purchase up to an additional 2,062,500 common units on the same terms and conditions as set forth above if the underwriters sell more than 13,750,000 common units in this offering.
Neither the Securities and Exchange Commission nor any other state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the common units on or about , 2014.
| Barclays | ||||||
| BofA Merrill Lynch | ||||||
| RBC Capital Markets | ||||||
| Deutsche Bank Securities |
||||||
| BMO Capital Markets | Baird | Simmons & Company International | Stephens Inc. |
Janney Montgomery Scott
Prospectus dated , 2014
i
ii
iii
You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.
iv
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Forward-Looking Statements."
The data included in this prospectus regarding the oil and gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of third-party sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Based on management's knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.
v
This summary highlights selected information contained elsewhere in this prospectus. You should carefully read this entire prospectus, including "Risk Factors" and the historical and unaudited pro forma combined financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units. You should read "Risk Factors" beginning on page 22 for more information about important factors that you should consider before purchasing our common units.
Unless the context otherwise requires, references in this prospectus to "JP Energy Partners," "the Partnership," "we," "our," "us," or like terms refer to JP Energy Partners LP and its subsidiaries, and references to "our general partner" refer to JP Energy GP II LLC, our general partner. References to "our sponsor" or "Lonestar" refer to Lonestar Midstream Holdings, LLC, which, together with JP Energy GP LLC and CB Capital Holdings II, LLC, two entities owned by certain members of our management, owns and controls our general partner. References to "ArcLight Capital" refer to ArcLight Capital Partners, LLC and references to "ArcLight Fund V" refer to ArcLight Energy Partners Fund V, L.P. References to "ArcLight" refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.
We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized in June 2011 by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of four business segments: (i) crude oil pipelines and storage, (ii) crude oil supply and logistics, (iii) refined products terminals and storage and (iv) NGL distribution and sales. Together our businesses provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:
- •
- owning, operating and developing midstream assets serving areas experiencing dramatic increases in drilling activity and
production growth, as well as serving key crude oil, refined product and NGL distribution hubs;
- •
- providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing
product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and
- •
- operating one of the largest portable propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.
We intend to continue to expand our business by acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs. Our crude oil businesses are situated in high-growth areas, including the Permian Basin, Mid-Continent and Eagle Ford shale, and provide us with a footprint to increase our volumes as these areas experience further drilling and production growth. In addition, we believe we have a competitive advantage with regard to the sourcing of opportunities to build, own and operate additional crude oil pipelines due to the insights in the market that we obtain while providing services to customers in our crude oil supply and logistics segment. We believe that our NGL distribution and sales segment will continue to grow due to our recent expansion
1
into new geographic markets, an increased market presence in our existing areas of operation and the increase in industrial and commercial applications for NGLs such as in oilfield and agricultural services.
Since our formation and the formation of our affiliate, JP Energy Development LP ("JP Development"), in July 2012, our management team has successfully established a strategic midstream platform through us and JP Development by way of 25 third-party acquisitions and numerous organic capital projects. The following table sets forth our aggregate net income and the Adjusted EBITDA for each of our business segments on a pro forma combined consolidated basis for the year ended December 31, 2013 and for the six months ended June 30, 2014.
| ($ in millions) |
Pro Forma Combined Consolidated Year Ended December 31, 2013 |
Pro Forma Combined Consolidated Six Months Ended June 30, 2014 |
|||||
|---|---|---|---|---|---|---|---|
Total net loss |
$ | (10.4 | ) | $ | (14.3 | ) | |
Adjusted EBITDA(1): |
|||||||
Crude oil pipelines and storage |
14.7 | 10.1 | |||||
Crude oil supply and logistics |
14.7 | 1.7 | |||||
Refined products terminals and storage |
16.1 | 5.1 | |||||
NGL distribution and sales |
15.5 | 7.6 | |||||
Discontinued operations(2) |
2.0 | 1.0 | |||||
Corporate and other(3) |
(27.5 | ) | (13.5 | ) | |||
Total Adjusted EBITDA |
$ | 35.5 | $ | 12.0 | |||
- (1)
- Adjusted
EBITDA is a financial measure not presented in accordance with generally accepted accounting principles in the United States ("GAAP"). For a
definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, its most directly comparable financial measures calculated in accordance
with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."
- (2)
- In
June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
- (3)
- Includes general partnership expenses associated with managing all reportable segments. Includes the impact of approximately $14.1 million and $5.8 million in professional fees incurred during the pro forma combined year ended December 31, 2013 and the pro forma combined six months ended June 30, 2014, respectively, related to the preparation and audit of financial statements contained in this prospectus, a significant portion of which we do not expect to incur in future periods. Excludes $3.5 million of incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.
Crude Oil Pipelines and Storage
Our crude oil pipelines and storage segment consists of two businesses: (i) an intrastate crude oil pipeline system in the Permian Basin known as the Silver Dollar Pipeline System and (ii) a crude oil storage facility located in Cushing, Oklahoma. As an early mover in areas with significant production of crude oil, we believe our established relationships with highly active producers and marketers in these regions will provide us with opportunities to expand our crude oil pipelines and storage segment through the construction of additional infrastructure.
2
The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Southern Wolfcamp play in the Midland Basin. The system currently consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and an interconnection to a third-party long-haul transportation pipeline. Our operations are underpinned by long-term, fee-based contracts with leading producers in the Southern Wolfcamp. One significant contract has a remaining term of approximately nine years and contains an acreage dedication related to crude oil production from approximately 110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately five years and contains a minimum volume commitment that was amended in March 2014 to significantly increase the volumes committed thereunder. This contract amendment and other anticipated commercial opportunities in the area have enabled us to undertake expansion projects involving the construction of approximately 30 miles of additional pipeline, including an interconnection to a second long-haul transportation pipeline, which we expect to be completed in the fourth quarter of 2014. We believe that these expansion projects will significantly increase the Silver Dollar Pipeline System's gathering footprint and take-away capacity and will provide our customers with access to new markets.
Our crude oil storage facility in Cushing, Oklahoma has an aggregate shell capacity of approximately 3.0 million barrels, all of which is dedicated to one customer pursuant to a long-term, fee-based storage services contract with a remaining term of approximately 3.0 years as of June 30, 2014. We generate crude oil storage revenues by charging this customer a fixed monthly fee per barrel of shell capacity that is not contingent on the customer's actual usage of our storage tanks.
Crude Oil Supply and Logistics
Our crude oil supply and logistics segment manages the physical movement of crude oil from origination to final destination largely through our network of owned and leased assets. Our assets and operations are located in areas of substantial crude oil production growth, including the Permian Basin, Mid-Continent and Eagle Ford shale. We own and operate a fleet of approximately 135 crude oil gathering and transportation trucks and approximately 30 crude oil truck injection stations and terminals. We also lease crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels pursuant to a long-term lease with a third party. Due to the limited pipeline infrastructure in some of the basins in which we operate, our crude oil gathering and transportation trucks provide immediate access for customers to transport their crude oil to the most advantageous outlets, including pipelines, rail terminals and local refining centers.
We primarily generate revenues in our crude oil supply and logistics segment by purchasing crude oil from producers, aggregators and traders at an index price less a discount and selling crude oil to producers, traders and refiners at a price linked to the same index. We also perform blending services in this segment whereby we purchase varying qualities of crude oil, which we blend in our leased storage tanks to WTI or other specifications. The majority of activities that are carried out within our crude oil supply and logistics segment are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside opportunities. Please read "—How We Conduct Our Business" for more details.
Refined Products Terminals and Storage
Our refined products terminals and storage segment has aggregate storage capacity of approximately 1.3 million barrels at two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our North Little Rock terminal has storage capacity of approximately 550,000 barrels from 11 tanks and is primarily supplied by a refined products pipeline operated by Enterprise TE Products Pipeline Company LLC, which we refer to as the TEPPCO Pipeline. Our Caddo Mills terminal has storage capacity of approximately 770,000 barrels from 10 tanks and is primarily supplied by the Explorer Pipeline. We generate fee-based revenues with customers with
3
whom we maintain longstanding relationships under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. We also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. A majority of the customers in our refined products terminals and storage segment are large, well-known oil companies and independent refiners.
NGL Distribution and Sales
Our NGL distribution and sales segment consists of three businesses in which we generate fee-based or margin-based revenue: (i) portable cylinder tank exchange, (ii) NGL sales and (iii) NGL transportation. We currently operate the third-largest propane cylinder exchange business in the United States, covering all 48 states in the continental United States through a network of over 17,700 distribution locations, which includes grocery stores, pharmacies, convenience stores and hardware stores. Our NGL sales business involves the retail, commercial and wholesale sale of NGLs and other refined products (including sales of gasoline and diesel to our oilfield service and agricultural customers) in six states in the Southwest and Midwest to approximately 88,800 customers through our distribution network of 44 customer service locations. Our NGL transportation business utilizes a fleet of approximately 43 hard shell tank trucks that gather and transport NGLs for producers, gas processing plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin.
The variety of services we offer in our NGL distribution and sales segment and the combination of our spring- and summer-weighted cylinder exchange business with our fall- and winter-weighted NGL sales business allows us to reduce the overall seasonal volatility in volumes. On a pro forma combined consolidated basis for the year ended December 31, 2013, we sold approximately 65 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 41% during the second and third quarters of 2013 and 59% during the first and fourth quarters of 2013.
We conduct our business through fee-based and margin-based arrangements.
Fee-based. We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide in our NGL distribution and sales segment. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from one month to 10 years.
Margin-based. We purchase and sell crude oil in our crude oil supply and logistics segment and NGLs and refined products in our NGL distribution and sales segment. A substantial portion of our margin related to the purchase and sale of crude oil in our crude oil supply and logistics segment is derived from "fee equivalent" transactions in which we concurrently purchase and sell crude oil at prices that are based on the same index, thereby generating revenue consisting of a margin plus our purchase, transportation, handling and storage costs. In our NGL distribution and sales segment, sales prices to our customers generally provide for a margin plus the cost of our products to our customers. We also perform blending services in our crude oil supply and logistics segment and our refined products terminals and storage segment, which allows us to generate additional margin based on the difference between our cost to purchase and blend the products and the market sales price of the finished blended product. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
4
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and cash flows. We expect to achieve this objective by pursuing the following business strategies:
- •
- Capitalize on organic growth opportunities and increase utilization of
our existing assets. We intend to identify and pursue organic growth opportunities and increase the utilization of our assets to
increase the cash flows of our existing businesses. For example, as of June 30, 2014, our Silver Dollar Pipeline System is connected to producers that control approximately 321,000 acres in
Crockett, Reagan and Schleicher counties, Texas and we are in advanced negotiations with these and other producers in the area to connect substantial additional acreage to the system. Additionally,
the recently-completed national expansion of the cylinder exchange business in our NGL distribution and sales segment has resulted in a new three-year contract with a national convenience store owner
and operator and its franchisees to provide propane cylinders to all of their gas stations in California, Oregon and Washington. We believe the national expansion of our cylinder exchange business
will allow us to compete for additional large-volume or national accounts.
- •
- Pursue strategic and accretive acquisition opportunities from our
affiliates and third parties. We intend to pursue accretive acquisition opportunities from our affiliates and third parties that will
complement, expand and diversify our asset base and cash flows. In addition, we intend to leverage the industry relationships of our management team to generate additional acquisition opportunities.
Historically, our acquisitions have largely been privately negotiated opportunities sourced through our management team's proprietary relationships.
- •
- Focus on fee-based and margin-based businesses with limited
commodity price exposure. We intend to continue adding operations that focus on providing services to our customers under
fee-based and margin-based arrangements. We plan to pursue opportunities in all of our segments with an emphasis on limiting commodity price exposure either through contract structure or
through a managed hedging program. Please read "—How We Conduct Our Business" for more information on how we manage our commodity price exposure.
- •
- Maintain financial flexibility and a disciplined capital structure. We intend to pursue a disciplined financial policy and maintain a conservative capital structure to allow us to pursue accretive acquisitions and execute on organic growth opportunities even in challenging capital market environments. Pro forma for this offering, we would have had $153.7 million in borrowing capacity under our revolving credit facility as of June 30, 2014. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $46.3 million as of June 30, 2014. We believe our financial flexibility positions us to take advantage of future growth opportunities without incurring debt beyond appropriate levels.
We believe that we are well-positioned to successfully execute our business strategies by capitalizing on the following competitive strengths:
- •
- Stable cash flows from contractual arrangements and diversified operations. Our contractual arrangements and diversified operations help us generate stable, predictable cash flows. We provide many of our services under long-term or evergreen contracts with customers with whom we have longstanding relationships. Pursuant to our contractual arrangements, substantially all of our cash flows are derived from fee-based or margin-based services, which minimizes our direct commodity price exposure. Our cash flows also benefit from our diverse operations in both geographic location and services offered to our customers.
5
- •
- Strategically located assets that provide organic growth
opportunities. The majority of our assets are located in areas characterized by strong demand for the services we currently provide as
well as a need for additional midstream infrastructure, providing us with attractive future growth prospects. For example, our Silver Dollar Pipeline System is among the first pipelines put into
service to provide crude oil transportation services to producers in the Southern Wolfcamp play, which has recently emerged as an area of significant new production growth in the Permian Basin.
Additionally, we believe the national expansion of our cylinder exchange business gives us the capability to compete for new large-volume or national accounts and provides us with economies of scale
and significant cost savings in product procurement, transportation and general administration.
- •
- Relationships with JP Development and ArcLight Fund
V. We consider our relationships with JP Development, our affiliate with whom we share a common management team, and ArcLight Fund V,
which has a substantial ownership interest in us, to be significant strengths. JP Development was formed in July 2012 by members of our management team and ArcLight for the express purpose of
supporting our growth. We acquired the Silver Dollar Pipeline System, a portfolio of crude oil supply and logistics assets and our fleet of NGL transportation trucks from JP Development in February
2014 and we believe that our relationship with JP Development will provide us with future growth opportunities. We also believe that ArcLight Fund V's substantial ownership interest in us will provide
ArcLight with an incentive to support our growth through opportunities other than those sourced from JP Development. Please read "—Our Relationship With JP Development and ArcLight."
- •
- Experienced and entrepreneurial management
team. Averaging approximately 17 years of experience in the energy industry, our management team has expertise in key areas of
the crude oil, refined products and natural gas liquids industries as well as in infrastructure development, acquisitions and the integration of acquired businesses. For example, since our formation
in May 2010, our management team has successfully grown our and JP Development's operations through 25 third-party acquisitions. Please read "Business—Our Acquisition History."
- •
- Strong sponsor with significant industry expertise. Through Lonestar, ArcLight Fund V is the principal owner of our general partner and the sole owner of JP Development. We believe that ArcLight Capital, which controls ArcLight Fund V, has substantial experience as a private equity investor in the energy industry, having managed the investment of more than $10 billion in energy companies and assets since its inception. By providing us with strategic guidance and financial expertise, we believe our relationship with ArcLight will greatly enhance our ability to grow our asset base and cash flows.
Our Relationship with JP Development and ArcLight
Our affiliate, JP Development, is a growth-oriented limited partnership that was formed in July 2012 by members of our management team and ArcLight for the express purpose of supporting our growth. JP Development intends to acquire growth-oriented midstream assets and to develop organic capital projects and then offer those assets for sale to us after they have been sufficiently developed such that their financial profile is suitable for us.
Since its formation, our management team and ArcLight have successfully grown JP Development through the acquisition of midstream assets and the execution of growth projects strategically located in our current areas of operation as well as new areas for expansion. In February 2014, we acquired from JP Development an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets for aggregate consideration valued at approximately $319 million. We refer to this transaction as the JP Development Dropdown. Please read "Business—Our Relationship With JP Development and ArcLight—JP Development Dropdown."
6
We believe that ArcLight Fund V's and our management's collective ownership of (i) 95% of our general partner, which owns all of our incentive distribution rights, (ii) a 56.1% limited partner interest in us and (iii) 100% of the partnership interests in JP Development create a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that will enhance the overall value of our business.
We believe that our relationship with JP Development and ArcLight will provide us with future growth opportunities. JP Development has granted us a right of first offer on all of its current and future assets and ArcLight Fund V has granted us a right of first offer with respect to a 50% indirect interest in Republic Midstream, LLC, an ArcLight portfolio company ("Republic"). The right of first offer with respect to JP Development's current and future assets is for a period of five years from the closing of this offering and the right of first offer with respect to Republic is for eighteen months from the closing of this offering. A description of JP Development's current assets and Republic, which we collectively refer to as the ROFO Assets, is provided below:
- •
- an approximately 115-mile intrastate crude oil pipeline, known as the Great Salt Plains Pipeline, that runs
from Cherokee, Oklahoma to Cushing, Oklahoma and serves the Mississippian Lime play;
- •
- an approximately 75-mile interstate crude oil pipeline, known as the Red River Pipeline, serving the Fort
Worth Basin that originates in Grayson County, Texas and runs to its principal terminus at the Elmore City Station in Garvin County, Oklahoma; and
- •
- a 100% member interest in Republic Midstream Gathering II, LLC, which owns a 50% indirect interest in Republic. Republic has agreed to build, own and operate certain crude oil midstream assets for Penn Virginia Corp. in the Eagle Ford shale region. Republic's initial assets will consist of a 180-mile crude oil gathering system in Gonzales and Lavaca Counties in Texas that will deliver the gathered volumes to a 144-acre central delivery terminal in Lavaca County that is capable of storing and blending crude oil volumes. Republic has also agreed to construct a 12-inch, 30-mile takeaway pipeline from the central delivery terminal. Subject to entering into definitive documentation, we have agreed to perform certain commercial services for Republic, including working with producers to transport crude oil from the wellhead to end markets.
Please read "Business—Our Relationship With JP Development and ArcLight" for additional discussion of JP Development's assets and "Certain Relationships and Related Party Transactions—Agreements With Affiliates in Connection With the Transactions—Right of First Offer Agreement" for additional information about our right of first offer.
While our relationship with JP Development and ArcLight is a significant strength, it is also a source of potential conflicts. Please read "Conflicts of Interest and Duties" and "Risk Factors—Risks Inherent in an Investment in Us—Our general partner and its affiliates, including Lonestar, JP Development, ArcLight Fund V and ArcLight Capital, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders." Additionally, we have no control over JP Development's business decisions or operations and JP Development is under no obligation to adopt a business strategy that favors us.
An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in "Risk Factors" and the other information in this prospectus before investing in our common units.
7
Recapitalization Transactions and Partnership Structure
At or prior to the closing of this offering, the following transactions, which we refer to as the recapitalization transactions, will occur.
Prior to the closing of this offering:
- •
- we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital
assets to our existing partners, pro rata in accordance with their ownership interest in us; and
- •
- each Class A common unit, Class B common unit and Class C common unit (collectively, the "Existing
Common Units") will split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and
- •
- an aggregate of 18,213,502 Existing Common Units held by our existing partners will automatically convert into 18,213,502 subordinated units representing a 80.3% interest in us prior to this offering, and a 50.0% interest in us after the closing of this offering, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the "Remaining Existing Common Units").
At the closing of this offering:
- •
- the Remaining Existing Common Units will automatically convert on a one-to-one basis into 4,463,502 common units
representing a 12.3% interest in us;
- •
- the 45 general partner units in us held by our general partner will be recharacterized as a non-economic
general partner interest in us;
- •
- we will issue 13,750,000 common units to the public in this offering representing a 37.7% interest in us; and
- •
- we will use the net proceeds from this offering and from the borrowings under our revolving credit facility for the purposes set forth in "Use of Proceeds."
8
Organizational Structure After the Recapitalization Transactions
After giving effect to the transactions described above, our units will be held as follows:
Public Common Units |
37.7 | % | ||
Lonestar: |
||||
Common Units |
10.1 | % | ||
Subordinated Units |
41.1 | % | ||
Management: |
||||
Common Units |
1.0 | % | ||
Subordinated Units |
4.0 | % | ||
Other Investors: |
||||
Common Units |
1.2 | % | ||
Subordinated Units |
4.9 | % | ||
Non-Economic General Partner Interest |
— | |||
Total |
100.0 | % | ||
The following diagram depicts our organizational structure after giving effect to the transactions described above.
- (1)
- Lonestar
is owned and controlled by ArcLight Energy Partners Fund V, L.P., an investment fund controlled by ArcLight Capital
Partners, LLC.
- (2)
- The
remaining 5.0% of our general partner is owned indirectly by one of the members of our board of directors. Please read "Security Ownership and Certain
Beneficial Owners and Management."
- (3)
- Includes the original investors in us, certain of our employees who hold unit awards and persons who were issued securities representing limited partner interests in us in connection with certain prior acquisitions. Please read "Security Ownership and Certain Beneficial Owners and Management."
9
Management of JP Energy Partners LP
We are managed and operated by the board of directors and executive officers of JP Energy GP II LLC, our general partner. Lonestar and certain members of management own our general partner and have the right to appoint its entire board of directors, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange (the "NYSE"). Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. For more information about the directors and executive officers of our general partner, please read "Management—Directors and Executive Officers of JP Energy GP II LLC."
In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, but we sometimes refer to these individuals in this prospectus as our employees.
Principal Executive Offices and Internet Address
Our principal executive offices are located at 600 East Las Colinas Boulevard, Suite 2000, Irving, Texas 75039, and our telephone number is (972) 444-0300. Our website is located at www.jpenergypartners.com. We intend to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission ("SEC") available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
Summary of Conflicts of Interest and Duties
General
Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that is in the best interests of its owners, including Lonestar and ArcLight. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including JP Development, Lonestar and ArcLight, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of our common units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read "Conflicts of Interest and Duties."
Partnership Agreement Replacement of Fiduciary Duties
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duties. Our partnership agreement also provides that
10
affiliates of our general partner, including Lonestar, JP Development and ArcLight, are not restricted from competing with us and that neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read "Conflicts of Interest and Duties—Duties of the General Partner" for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units and subordinated units.
ArcLight, Lonestar and JP Development May Compete Against Us
Although our relationships with ArcLight, Lonestar and JP Development are valuable to us, they are also a source of potential conflict. For example, our partnership agreement does not prohibit ArcLight, Lonestar, JP Development or their affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, ArcLight and Lonestar or their affiliates, other than JP Development and ArcLight Fund V, which are subject to the right of first offer described under "—Our Relationship With JP Development and ArcLight," may invest in other publicly traded partnerships or acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets.
For a more detailed description of the conflicts of interest and the duties of our general partner, please read "Conflicts of Interest and Duties."
11
| Common units offered to the public | 13,750,000 common units. | |
15,812,500 common units if the underwriters exercise in full their option to purchase additional common units from us. |
||
Units outstanding after this offering |
18,213,502 common units and 18,213,502 subordinated units, each representing a 50.0% limited partner interest in us. In addition, our general partner will own a non-economic general partner interest in us. |
|
Use of proceeds |
Prior to the closing of this offering, we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital to our existing partners, pro rata in accordance with their ownership interest in us. |
|
We expect to receive net proceeds of approximately $257.1 million from the sale of common units in this offering based on the initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and structuring fees but before estimated offering expenses. |
||
We intend to use the net proceeds from this offering to (i) pay estimated offering expenses of approximately $2.0 million, (ii) redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million, (iii) repay $195.6 million of debt outstanding under our revolving credit facility and (iv) replenish approximately $17.1 million of working capital. |
||
Immediately following the repayment of a portion of the outstanding debt under our revolving credit facility with a portion of the net proceeds from this offering, we will borrow approximately $75.0 million thereunder. We will use the proceeds from that borrowing to replenish our working capital. |
||
The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be used to redeem from Lonestar a number of common units from our existing partners, pro rata, equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Please read "Underwriting." |
||
Cash distributions |
We intend to make a minimum quarterly distribution of $0.3250 per unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. |
12
| For the quarter in which this offering closes, we will pay a prorated distribution on our units covering the period from the completion of this offering through December 31, 2014, based on the actual length of that period. | ||
In general, we will pay any cash distributions we make each quarter in the following manner: |
||
|
• first, 100% to the holders of common units, until each common unit has received a minimum quarterly distribution of $0.3250 plus any arrearages from prior quarters; |
|
|
• second, 100% to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.3250; and |
|
|
• third, 100% to all unitholders, pro rata, until each unit has received a distribution of $0.37375. |
|
If cash distributions to our unitholders exceed $0.37375 per unit in any quarter, our general partner will receive increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount due to its ownership of all of our incentive distribution rights. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions." |
||
If we do not generate sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders. |
||
The amount of pro forma available cash generated during the year ended December 31, 2013 and the twelve months ended June 30, 2014 would not have been sufficient to allow us to pay the minimum quarterly distribution on all of our units during those periods. Specifically, the amount of pro forma available cash generated during the year ended December 31, 2013 would have been sufficient to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Likewise, the amount of pro forma available cash generated during the twelve months ended June 30, 2014 would have been sufficient to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period. |
13
| We believe, based on our financial forecast and related assumptions included in "Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2015," that we will have sufficient available cash to pay the aggregate minimum quarterly distribution of $47.4 million on all of our common units and subordinated units for the twelve months ending June 30, 2015. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions." | ||
Subordinated units |
Lonestar and certain members of our management will initially own approximately 90.2% of our subordinated units. The principal difference between our common units and our subordinated units is that for any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages. |
|
Conversion of subordinated units |
The subordination period will end on the first business day after we have earned and paid at least (i) $1.30 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2017 or (ii) $1.95 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distributions on the incentive distribution rights for any four-quarter period ending on or after September 30, 2015, in each case provided there are no arrearages on our common units at that time. |
|
The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal. |
||
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will no longer be entitled to arrearages. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period." |
14
| Issuance of additional units | Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read "Units Eligible for Future Sale" and "Our Partnership Agreement—Issuance of Additional Securities." | |
Limited voting rights |
Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of our outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, affiliates of our general partner, including Lonestar, will own an aggregate of 56.1% of our common and subordinated units (or 11.9% and 90.2%, respectively, of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give affiliates of our general partner, including Lonestar, the ability to prevent the removal of our general partner. Please read "Our Partnership Agreement—Voting Rights." |
|
Limited call right |
If at any time our general partner and its affiliates own more than 80.0% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of our remaining common units at a price equal to the greater of (i) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. At the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 22.1% of our common units. Please read "Our Partnership Agreement—Limited Call Right." |
15
| Redemption of ineligible holders | Units held by persons who our general partner determines are not "citizenship eligible holders" or "rate eligible holders" will be subject to redemption. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, and will generally include individuals and entities who are United States citizens. Rate eligible holders are: | |
|
• individuals or entities subject to United States federal income taxation on the income generated by us; or |
|
|
• entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity's owners are domestic individuals or entities subject to such taxation. |
|
We will have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not a citizenship eligible holder or a rate eligible holder or that has failed to certify or has falsely certified that such holder is a citizenship eligible holder or a rate eligible holder. The redemption price will be equal to the market price of the common units as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not a citizenship eligible holder or a rate eligible holder will not be entitled to voting rights. |
||
Please read "Our Partnership Agreement—Redemption of Ineligible Holders." |
||
Estimated ratio of taxable income to distributions |
We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.30 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.26 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" for the basis of this estimate. |
16
| Material federal income tax consequences | For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Federal Income Tax Consequences." | |
Directed Unit Program |
At our request, the underwriters have reserved for sale up to 5.0% of the common units being offered by this prospectus for sale at the initial public offering price to the directors, director nominees and executive officers of our general partner and certain other employees and consultants of our general partner and its affiliates. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read "Underwriting—Directed Unit Program." |
|
Exchange listing |
We have been approved to list our common units on the New York Stock Exchange under the symbol "JPEP." |
17
Summary Historical and Pro Forma Combined Consolidated Financial and Operating Data
The table set forth below presents, as of the dates and for the periods indicated, our summary historical and pro forma combined consolidated financial and operating data.
The summary historical consolidated financial data presented as of December 31, 2012 and December 31, 2013 and for the years ended December 31, 2011, December 31, 2012 and December 31, 2013 have been derived from our audited historical consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2013 and June 30, 2014 and for the six months ended June 30, 2013 and June 30, 2014 are derived from our unaudited historical condensed consolidated financial statements.
The summary pro forma combined consolidated statement of operations for the six months ended June 30, 2014 includes the pro forma effects of the recapitalization transactions, including this offering, described under "—Recapitalization Transactions and Partnership Structure" as if the recapitalization transactions, including this offering, occurred on January 1, 2013. The summary pro forma combined consolidated balance sheet as of June 30, 2014 was prepared as if the recapitalization transactions, including this offering, occurred on June 30, 2014. The summary pro forma combined consolidated statement of operations for the year ended December 31, 2013 gives effect to (i) our acquisition of the Silver Dollar Pipeline System as if it had occurred on January 1, 2013 and (ii) the recapitalization transactions, including this offering, as if they had occurred on January 1, 2013.
During 2013, we determined that our previously issued audited consolidated financial statements as of December 31, 2012 and results of operations for the year ended December 31, 2012 contained errors. We evaluated those errors and determined that the impact of these errors was material to the results of operations for the year ended December 31, 2012. Accordingly, our previously audited consolidated balance sheet at December 31, 2012 and the statement of operations and statement of cash flows for the year ended December 31, 2012 have been restated to reflect the correction of the errors, including the correction of immaterial errors. Please read note 3 of our consolidated financial statements included elsewhere in this prospectus.
On February 12, 2014, we acquired certain assets from JP Development. Because we and JP Development are both affiliates of ArcLight, this was a transaction between commonly controlled entities and we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the acquired assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the acquired assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the acquired assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."
For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with our unaudited pro forma combined consolidated financial statements and audited and unaudited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma combined consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.
The following table presents Adjusted EBITDA, distributable cash flow and adjusted gross margin, financial measures that are not presented in accordance with GAAP. We use Adjusted EBITDA, distributable cash flow and adjusted gross margin in our business as we believe they are important supplemental measures of our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash
18
equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define distributable cash flow as Adjusted EBITDA less net cash interest paid, income taxes paid and maintenance capital expenditures. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gains (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).
For a reconciliation of Adjusted EBITDA, distributable cash flow and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."
19
| |
|
|
|
|
|
Pro Forma | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
|
Six Months Ended June 30, |
||||||||||||||||||
| |
Year Ended December 31, | |
Six Months Ended June 30, 2014 |
|||||||||||||||||||
| |
Year Ended December 31, 2013 |
|||||||||||||||||||||
($ in thousands, except per unit amounts)
|
2011 | 2012(1) | 2013(1) | 2013 | 2014 | |||||||||||||||||
| |
|
(Restated and Recast) |
|
(unaudited) |
(unaudited) |
|||||||||||||||||
Statement of Operations Data: |
||||||||||||||||||||||
Total revenue |
$ | 67,156 | $ | 427,581 | $ | 2,102,233 | $ | 987,804 | $ | 865,817 | $ | 2,105,201 | $ | 865,817 | ||||||||
Costs and expenses: |
||||||||||||||||||||||
Cost of sales, excluding depreciation and amortization |
49,048 | 368,791 | 1,964,631 | 918,957 | 798,193 | 1,964,631 | 798,193 | |||||||||||||||
Operating expenses |
9,584 | 28,640 | 61,925 | 28,202 | 35,266 | 62,996 | 35,266 | |||||||||||||||
General and administrative |
6,053 | 20,983 | 45,284 | 20,313 | 23,879 | 45,699 | (2) | 23,838 | (2) | |||||||||||||
Depreciation and amortization |
2,841 | 13,856 | 33,345 | 15,186 | 20,165 | 36,524 | 20,165 | |||||||||||||||
Loss on disposal of assets |
68 | 1,142 | 1,492 | 998 | 661 | 1,492 | 661 | |||||||||||||||
Operating income (loss) |
(438 | ) | (5,831 | ) | (4,444 | ) | 4,148 | (12,347 | ) | (6,141 | ) | (12,306 | ) | |||||||||
Other income (expense): |
||||||||||||||||||||||
Interest (expense) |
(633 | ) | (3,405 | ) | (9,075 | ) | (3,815 | ) | (5,551 | ) | (4,714 | ) | (2,308 | ) | ||||||||
Loss on extinguishment of debt |
(95 | ) | (497 | ) | — | — | (1,634 | ) | — | — | ||||||||||||
Other income, net |
— | 247 | 688 | 195 | 504 | 688 | 504 | |||||||||||||||
Income (loss) before income taxes |
(1,166 | ) | (9,486 | ) | (12,831 | ) | 528 | (19,028 | ) | (10,167 | ) | (14,110 | ) | |||||||||
Income tax (expense) benefit |
(35 | ) | (222 | ) | (208 | ) | (305 | ) | (156 | ) | (227 | ) | (156 | ) | ||||||||
Net income (loss) from continuing operations |
(1,201 | ) | (9,708 | ) | (13,039 | ) | 223 | (19,184 | ) | (10,394 | ) | (14,266 | ) | |||||||||
Net income (loss) from discontinued operations(3) |
— | 1,320 | (1,182 | ) | (23 | ) | (9,608 | ) | — | — | ||||||||||||
Net income (loss) |
$ | (1,201 | ) | $ | (8,388 | ) | $ | (14,221 | ) | $ | 200 | $ | (28,792 | ) | $ | (10,394 | ) | $ | (14,266 | ) | ||
General partner's interest in pro forma net income (loss) |
||||||||||||||||||||||
Common unit holder's interest in pro forma net income (loss) |
(5,197 | ) | (7,133 | ) | ||||||||||||||||||
Subordinated unit holder's interest in pro forma net income (loss) |
(5,197 | ) | (7,133 | ) | ||||||||||||||||||
Pro forma net income per common unit |
(0.29 | ) | (0.39 | ) | ||||||||||||||||||
Pro forma net income per subordinated unit |
(0.29 | ) | (0.39 | ) | ||||||||||||||||||
Weighted average number of limited partner units outstanding |
||||||||||||||||||||||
Common units |
18,213,502 | 18,213,502 | ||||||||||||||||||||
Subordinated units |
18,213,502 | 18,213,502 | ||||||||||||||||||||
Statement of Cash Flows Data: |
||||||||||||||||||||||
Cash provided by (used in): |
||||||||||||||||||||||
Operating activities |
$ | (5,895 | ) | $ | (6,990 | ) | $ | 13,882 | $ | 24,778 | $ | 7,572 | ||||||||||
Investing activities(4) |
(26,860 | ) | (292,334 | ) | (27,735 | ) | (13,986 | ) | (4,936 | ) | ||||||||||||
Financing activities(5) |
34,825 | 304,991 | (4) | 6,988 | (11,482 | ) | (4,744 | ) | ||||||||||||||
Other Financial Data(6): |
||||||||||||||||||||||
Adjusted gross margin |
18,108 | 57,203 | 136,491 | $ | 68,938 | $ | 68,553 | $ | 139,459 | $ | 68,553 | |||||||||||
Adjusted EBITDA |
$ | 2,825 | $ | 14,560 | $ | 34,284 | 23,855 | 12,038 | 35,527 | 12,035 | ||||||||||||
Distributable cash flow |
1,902 | 11,341 | 23,755 | 18,710 | 6,286 | 24,288 | 7,044 | |||||||||||||||
Balance Sheet Data: |
||||||||||||||||||||||
Cash and cash equivalents |
$ | 4,432 | $ | 10,099 | $ | 3,234 | $ | 9,409 | $ | 1,126 | $ | 108,451 | ||||||||||
Accounts receivable, net |
12,246 | 80,551 | 122,919 | 79,038 | 158,265 | 50,940 | ||||||||||||||||
Property, plant and equipment, net |
27,720 | 191,864 | 238,093 | 194,201 | 232,690 | 232,690 | ||||||||||||||||
Total assets |
65,931 | 562,124 | 843,402 | 556,910 | 842,472 | 839,713 | ||||||||||||||||
Total long-term debt (including current maturities) |
16,948 | 167,739 | 184,846 | 165,901 | 183,322 | 76,722 | ||||||||||||||||
Total partners' capital |
41,466 | 314,153 | 533,393 | 308,808 | 505,506 | 609,601 | ||||||||||||||||
Operating Data(7): |
||||||||||||||||||||||
Crude oil pipeline throughput (Bbl/d) |
— | — | 13,738 | (7) | — | 19,652 | 8,885 | (8) | 19,652 | |||||||||||||
Crude oil sales (Bbl/d) |
— | 24,201 | 53,471 | 51,372 | 42,411 | 53,471 | 42,411 | |||||||||||||||
Refined products terminals throughput (Mgal/d) |
— | 2,400 | 2,901 | 2,834 | 2,699 | 2,901 | 2,699 | |||||||||||||||
NGL and refined product sales (Gal/d) |
61,314 | 128,775 | 180,850 | 182,463 | 199,016 | 180,850 | 199,016 | |||||||||||||||
- (1)
- Our historical combined consolidated financial and operating data for the years ended December 31, 2012 and 2013 have been retrospectively adjusted for the JP Development Dropdown. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."
20
- (2)
- Includes
the impact of professional fees of approximately $14.1 million and $5.8 million for the pro forma combined year ended
December 31, 2013 and the pro forma combined six months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur in future periods. Excludes estimated
incremental cash expense associated with being a publicly traded partnership of approximately $3.5 million, including costs associated with SEC reporting requirements, tax return and
Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent
fees, incremental officer and director liability expenses and director compensation.
- (3)
- In
June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
- (4)
- Cash
used in investing activities includes the cash consideration paid for third party acquisitions during the years ended December 31, 2011, 2012
and 2013, as described in greater detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations."
- (5)
- Cash
provided by financing activities for the year ended December 31, 2012 includes the issuance of units and borrowings under our 2011 revolving
credit facility to finance the purchase of certain third party acquisitions during the year ended December 31, 2012, as described in greater detail in "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
- (6)
- Adjusted
gross margin, Adjusted EBITDA and distributable cash flow are financial measures that are not presented in accordance with GAAP. Please read
"Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."
- (7)
- Represents
the average daily throughput volume in our crude oil pipelines and storage segment, the average daily sales volume in our crude oil supply and
logistics segment, the average daily throughput volume in our refined products terminals and storage segment and the average daily sales volume in our NGL distribution and sales segment.
- (8)
- The Silver Dollar Pipeline System was placed into service in April 2013 and acquired by us in October 2013. Average throughput for the year ended December 31, 2013 represents throughput from the date of acquisition through year end, while average throughput for the pro forma year ended December 31, 2013 represents throughput from the date the Silver Dollar Pipeline System was placed into service through year end.
21
Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.
In order to pay the minimum quarterly distribution of $0.3250 per unit per quarter, or $1.30 per unit on an annualized basis, we will require available cash of approximately $11.8 million per quarter, or $47.4 million per year, based on the number of common and subordinated units that will be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
- •
- the price of, and the demand for, crude oil, refined products and NGLs in the markets we serve;
- •
- the volumes of crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and
our NGL sales volumes;
- •
- the fees we receive for the crude oil, refined products and NGL volumes we handle;
- •
- pressures from our competitors, some of which may have significantly greater resources than us;
- •
- the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass
along cost increases to our customers;
- •
- competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;
- •
- the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to
replace such contracts and/or customers;
- •
- leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;
- •
- the level of our operating, maintenance and general and administrative expenses; and
- •
- regulatory action affecting our existing contracts, our operating costs or our operating flexibility.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
- •
- the level of capital expenditures we make;
- •
- our cost of acquisitions, if any;
- •
- our debt service requirements and other liabilities;
- •
- expenses that our general partner incurs on our behalf and are reimbursed by us, which expenses are not subject to any caps or other limits pursuant to our partnership agreement;
22
- •
- fluctuations in our working capital needs;
- •
- our ability to borrow funds and access the capital markets;
- •
- restrictions contained in our revolving credit facility and other debt agreements;
- •
- the amount of cash reserves established by our general partner; and
- •
- other business risks affecting our cash levels.
On a pro forma basis we would not have had sufficient distributable cash flow to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2013 or for the twelve months ended June 30, 2014, with shortfalls of $23.1 million for the year ended December 31, 2013 and $33.0 million for the twelve months ended June 30, 2014.
The amount of pro forma distributable cash flow generated during the year ended December 31, 2013 was $24.3 million, which would have allowed us to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $23.1 million for the year ended December 31, 2013. The amount of pro forma distributable cash flow generated during the twelve months ended June 30, 2014 was $14.4 million, which would have allowed us to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $33.0 million for the twelve months ended June 30, 2014. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Cash Distribution Policy and Restrictions on Distributions." If we are not able to generate additional cash for distribution to our unitholders in future periods, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.
The assumptions underlying the forecast of Adjusted EBITDA, distributable cash flow and adjusted gross margin that we include in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
The forecast set forth in "Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA, distributable cash flow and adjusted gross margin for the twelve months ending June 30, 2015. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in transported, sold and stored volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.
A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues.
A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues, which could have a material adverse effect on our financial condition,
23
results of operations and cash flows. Factors that could lead to a decrease in market demand for crude oil, refined products or NGLs include:
- •
- lower demand by consumers for refined products or crude oil as a result of adverse economic conditions, an increase in the
market price of crude oil, an increase in the market price of gasoline or other refined products, use by consumers of alternative fuels or an increase in the fuel economy of vehicles;
- •
- lower drilling activity in the areas served by our crude oil gathering and transportation business as a result of a
decrease in the market price of crude oil or for other reasons; and
- •
- fluctuations in the demand for crude oil, such as those caused by refinery downtime or shutdowns.
Certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, we may experience declines in our margin and profitability if our volumes decrease.
We have some short-term contracts and other contracts that can be canceled on 60 days' notice and will have to be renegotiated or replaced periodically. Our failure to replace contracts that are canceled or expire on acceptable terms, or at all, could cause our revenues to decline and reduce our ability to make distributions to our unitholders.
Many of our contracts in our NGL sales and distribution segment have terms as short as one month, and substantially all of our contracts with customers in our refined products terminals and storage segment have evergreen provisions after an initial term of six months to two years and are cancellable on as little as 60 days' notice. In addition, many of our contracts in our crude oil supply and logistics segment either have terms as short as one month or have evergreen provisions and are cancellable on as little as 60 days' notice. As these NGL or crude oil contracts expire or if a refined products contract is canceled, we may not be able to extend, renegotiate or replace these contracts and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. In addition, while the majority of the revenue in our crude oil pipelines and storage segment is generated pursuant to long-term contracts, our customers may negotiate for more favorable terms upon any renewal.
Our ability to extend or replace contracts could be impacted by a number of factors beyond our control, including competition, the level of supply and demand for crude oil and refined products in our areas of operations, general economic conditions and regulatory developments. To the extent we are unable to renew our contracts on terms that are favorable to us, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.
We face intense competition in all of our business segments. Competitors that are able to supply our customers with similar services or products at a lower price could reduce our revenues.
We are subject to competition from other providers of crude oil transportation, storage, supply and logistics services, refined products terminals and storage services and NGL distribution and sales services, including national, regional and local companies engaged in these activities. Some of these competitors are substantially larger than us and may have greater financial resources. Our ability to compete could be affected by many factors, including:
- •
- price competition;
- •
- the perception that another company can provide better service; and
24
- •
- the availability of alternative supply points, or supply points located closer to the operations of our customers.
In addition, our general partner and its affiliates, including JP Development, Lonestar and ArcLight, may engage in competition with us. If we are unable to compete with services offered by our competitors, including possibly our general partner or its affiliates, it could have a material adverse effect on our financial condition, results of operations and cash flows.
We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
Prior to the completion of this offering, we have been a private entity with limited accounting personnel and other supervisory resources to adequately execute our accounting processes and address our internal control over financial reporting. In connection with the audits of our financial statements for the years ended December 31, 2011, 2012 and 2013, our independent registered public accounting firm identified material weaknesses in internal control over financial reporting relating to (1) accounting resources and policies (including maintaining an effective control environment), (2) accounting for business combinations and (3) information technology. A "material weakness" is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We did not have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements. As a result, we did not design and maintain:
- •
- formal accounting policies and formal review controls;
- •
- effective controls over accounting for business combinations, including controls related to the valuation of assets
acquired and liabilities assumed, and the integration of the businesses by applying consistent accounting policies and processes to determine compliance with industry standards and regulations; and
- •
- adequate policies and procedures with respect to the primary components of information technology general controls, including the approval and review of access controls, system implementation and migration controls, and change management controls.
These material weaknesses resulted in audit adjustments in the years ended December 31, 2011, 2012 and 2013 and the three months ended March 31, 2012 and 2013, and six months ended June 30, 2013, and a restatement of our financial statements for the years ended December 31, 2011 and 2012, and the three months ended March 31, 2012 and 2013. Management has determined that the excessive product gains at a refined products terminal described in Note 10 to the consolidated financial statements for the six months ended June 30, 2014 was an additional effect of the material weakness related to business combinations and information technology described above. Also, management has determined that the excessive product gains at a refined products terminal relate to not designing and maintaining effective controls to determine compliance with industry standards and regulations during the integration of the acquired business. As a result, the description of the business combination material weakness at June 30, 2014 was expanded to include this aspect of the material weakness related to integration of acquired businesses.
While we have begun the process of implementing additional processes and controls related to accounting and financial reporting, we will not complete our implementation until after this offering is completed. During the course of the implementation, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above or any newly identified material weakness could result in a misstatement of our accounts or disclosures that would result in a material
25
misstatement of our annual or interim consolidated financial statements that would not be prevented or detected.
If we do not properly maintain and improve our measurement and quality control processes and procedures across all of our business segments, we may have measurement and quality errors or contamination, which may result in lost revenues or the incurrence of additional costs.
We are implementing measurement and quality control processes and procedures across all of our business segments. To the extent we do not properly maintain and improve such procedures, we may have measurement and quality errors or contamination that could result in lost revenues or the incurrence of additional costs. For example, in the third quarter of 2014 we became aware that certain of our measurement and quality control processes at our North Little Rock terminal were not in compliance with certain industry standards and had resulted in excessive product gains for the North Little Rock terminal. We have notified our customers and are in the process of returning a certain amount of refined products to such customers for the period from November 2012 (the month we acquired the North Little Rock terminal) through July 2014. If we are unable to reach a resolution on this matter, customers may assert claims against us for damages. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims, if any are ultimately asserted. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur costs that could have a negative effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We are not currently required to make an assessment of our internal control over financial reporting.
We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002 ("Sarbanes Oxley") and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC's rules implementing Sections 302 and 404 of Sarbanes Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Although we will be required to disclose changes made to our internal control over financial reporting and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of Sarbanes Oxley and our independent registered public accounting firm will not be required to issue an attestation report on the effectiveness of our internal control over financial reporting until the fiscal year ending December 31, 2015. In order to have effective control over financial reporting, we will need to implement additional internal controls, reporting systems and procedures.
Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal control over financial reporting, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal control over financial reporting will subject us to regulatory scrutiny and could result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
26
Because of the natural decline in production from our customers' existing wells in our areas of operation, we depend, in part, on producers replacing declining production and also on our ability to secure new sources of crude oil. Any decrease in the volumes of crude oil that we transport could adversely affect our business and operating results.
The crude oil volumes that support our crude oil pipelines and storage segment and crude oil supply and logistics segment depend on the level of production from crude oil wells on which we rely for throughput or sales and transportation volumes, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput or sales and transportation volumes in these segments, we must obtain new sources of crude oil. In our crude oil pipelines and storage segment, the primary factors affecting our ability to obtain non-dedicated sources of crude oil include (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells on which we rely for throughput or sales and transportation volumes or the rate at which production from such wells declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:
- •
- the availability and cost of capital;
- •
- prevailing and projected oil, natural gas and NGL prices;
- •
- demand for oil, natural gas and NGLs;
- •
- levels of reserves;
- •
- geological considerations;
- •
- environmental or other governmental regulations, including the availability of drilling permits and the regulation of
hydraulic fracturing; and
- •
- the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of oil reserves. Drilling and production activity generally decreases as oil prices decrease. Declines in oil prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in exploration and production activity. Any sustained decline of exploration or production activity in our areas of operation could lead to reduced utilization of our assets.
Because of these and other factors, even if oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain throughput in our crude oil pipelines and storage segment and our sales and transportation volumes in our crude oil supply and logistics segment, our revenue and cash flow could be reduced and our ability to make cash distributions to our unitholders could be adversely affected.
We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis; therefore, in the future, volumes of oil on our Silver Dollar Pipeline System could be less than we anticipate.
We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to our Silver Dollar Pipeline System or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our Silver Dollar Pipeline System are less than we anticipate and if our customers are unable to secure additional sources of crude oil production it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
27
Our success in our crude oil pipelines business depends, in part, on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.
Our Silver Dollar Pipeline System is located in the Southern Wolfcamp and we intend to focus future capital expenditures on developing our business in this area. Due to our focus on the Southern Wolfcamp, an adverse development in oil production from this area would have a greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Southern Wolfcamp basin could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
We may not be able to increase throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our crude oil pipelines and storage segment.
Our ability to increase our throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which our Silver Dollar Pipeline System has available takeaway capacity. To the extent that we lack available capacity on our Silver Dollar Pipeline System for additional volumes, we may not be able to compete effectively with third-party systems for additional oil production in our areas of operation. In addition, our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to contracts that are effectively fee-based. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.
Our crude oil supply and logistics operations involve market and regulatory risks.
As part of our crude oil supply and logistics activities, we purchase crude oil at prices determined by prevailing market conditions. Following our purchase of crude oil, we generally resell crude oil at a higher price under a sales contract that is generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our crude oil logistics operations may be affected by the following factors:
- •
- our ability to negotiate crude oil purchase and sales agreements in changing markets on a timely basis;
- •
- reluctance of customers to enter into long-term purchase contracts;
- •
- consumers' willingness to use other fuels instead of the end products in the crude oil supply chain;
- •
- the timing of imbalance or volume discrepancy corrections and their impact on our financial results;
- •
- the ability of our customers to make timely payment; and
- •
- any inability we may have to match purchase and sale of crude oil on comparable terms.
We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.
We rely on a limited number of customers for a substantial portion of our revenues. Glencore Ltd. and Chesapeake Energy Marketing, Inc. each accounted for more than 10% of our total revenue for the year ended December 31, 2013, at approximately 50% and 13%, respectively. Parnon Energy, Inc. and Glencore, Ltd. each accounted for more than 10% of our total revenue for the year ended December 31, 2012, at approximately 30% and 17%, respectively. Glencore, Ltd., Chesapeake Energy Marketing, Inc. and Phillips 66 each accounted for more than 10% of our total revenue for the six
28
months ended June 30, 2014, at approximately 37%, 15% and 12%, respectively. Glencore, Ltd. accounted for more than 10% of our total revenue for the six months ended June 30, 2013, at approximately 50%. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms or at all. In addition, these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. Furthermore, our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Midstream capacity constraints and interruptions could impact our operations.
We rely on various midstream facilities and systems in connection with our crude oil supply and logistics operations. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of the supply in our crude oil supply and logistics business may be interrupted or shut-in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed in connection with our crude oil supply and logistics operations. Such interruptions or constraints could negatively impact our profitability.
The risk management policy governing our crude oil supply activities cannot eliminate all risks associated with our crude oil supply and logistics business, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.
We have in place a risk management policy that seeks to establish limits for the exposure in our crude oil supply and logistics business by requiring that we restrict net open positions through the concurrent purchase and sale of like quantities of crude oil to create transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Our risk management policy, however, cannot eliminate all risks. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.
Moreover, we are exposed to price movements on products that are not hedged, including certain of our inventory, such as linefill, which must be maintained to operate our crude oil pipeline system. We are also exposed to certain price risks related to basis differentials. Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality at a location or at a time that differs from the specific delivery terms with respect to grade, quality, time or location of the applicable offsetting agreement. If this occurs, we may not be able to use the physical markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.
We are also subject to the risk that employees of our general partner involved in our crude oil supply operations may not comply at all times with our risk management policy. We cannot ensure that all violations of our risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.
29
A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for the services we provide in our crude oil storage business.
In recent years, a shortfall in takeaway pipeline capacity has at times led to an oversupply of crude oil at Cushing. This was cited as a principal reason for the decline in the West Texas Intermediate Index ("WTI Index") price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index over the same period. While the WTI Index price has recovered compared to the Brent Crude Index, a renewed decline in the WTI Index price relative to other index prices may reduce demand for our transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
The results of our crude oil storage business could be adversely affected during periods in which the overall forward market for crude oil is backwardated.
The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Conversely, a backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered for future delivery are expected to be lower. Accordingly, a backwardated market can negatively impact the demand for crude oil storage. If the forward market for crude oil is backwardated at times when we are renewing our crude oil storage contract or entering into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.
All of our operations have indirect exposure to changes in commodity prices and some of our operations have direct exposure to commodity price changes.
Our operations have limited direct exposure to changes in commodity prices. However, the volumes of crude oil that we transport, store or supply, refined products that we handle and NGLS that we distribute and sell are indirectly affected by commodity prices because many of our customers have direct exposure to commodity prices. If our customers are negatively impacted by changes in commodity prices, they may, among other things, reduce the services they purchase from us. For example, lower crude oil prices could suppress drilling activity, which would reduce demand for our crude oil pipeline, storage or supply and logistics services, while higher refined products prices could decrease consumer demand for refined products, which could reduce demand for services we provide at our refined products terminals.
In addition, in our refined products terminals and storage segment, we also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. Our blending activities are subject to direct commodity price exposure. Any significant reduction in the amount of services we provide to our customers because of direct or indirect commodity price exposure and any significant reduction in the refined products that we sell could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
We do not operate our crude oil storage facility.
TEPPCO Partners L.P., a wholly owned subsidiary of Enterprise Products Partners L.P., serves as the operator of our crude oil storage facility. Under the operating agreement governing TEPPCO's operation of our facility, we are liable for any losses or claims arising from damage to our property or personal injury claims of our personnel that may result from the actions of the operator, even if such losses or claims result from the operator's gross negligence or willful misconduct. If disputes arise over
30
operation of our crude oil storage facility, or if our operator fails to provide the services contracted under the agreement, our business, results of operation, financial condition and ability to make cash distributions to our unitholders could be adversely affected.
Increased trucking regulations may increase our costs or make it more difficult for us to attract or retain qualified drivers, which could negatively affect our results of operations.
In connection with the services we provide, we operate as a motor carrier and, therefore, are subject to regulation by the Department of Transportation (the "DOT"), and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry that we are subject to, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. These possible changes include increasingly stringent environmental regulations, changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
In addition, the already substantial competition for qualified drivers in the trucking industry may increase because of regulatory requirements. For instance, Comprehensive Safety Analysis 2010 ("CSA") has been implemented by the Federal Motor Carrier Safety Administration, an agency of the DOT, to monitor and improve commercial motor vehicle safety by measuring the safety record of both the motor carrier and the driver. The requirements of CSA could shrink the pool of qualified drivers and increase the costs we incur in order to attract, train and retain qualified drivers. In addition, a shortage of qualified drivers could increase driver turnover rates, which might limit growth in our crude oil supply and logistics or other segments.
Our refined products terminals are dependent upon their interconnections with terminals and pipelines owned and operated by others.
Our refined products terminals are dependent upon their interconnections with other terminals and pipelines owned and operated by third parties to reach end markets and as a significant source of supply. Our North Little Rock terminal is supplied by the TEPPCO Pipeline while our Caddo Mills terminal is supplied by the Explorer Pipeline. Reduced or interrupted throughput on these pipelines or outages at terminals with which our refined products terminals share interconnects because of weather or other natural events, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver refined products to our customers from our terminals or receive products for storage at our terminals, which could adversely affect our cash flows and revenues. In addition, in the event that one of the pipelines depended upon by either of our refined products terminals modifies its tariff to discontinue service for one or more of the products throughput at our terminals, we will have to discontinue selling or secure an alternate supply of such product. This could have a material adverse impact on the throughput volumes and revenues of our refined products terminals and storage segment.
The assets in our refined products terminals and storage segment have been in service for several decades.
Our refined products terminals and storage assets are generally long-lived assets. Our North Little Rock terminal has been in service for approximately 34 years, and our Caddo Mills terminal has been in service for approximately 29 years. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
31
Warm weather in the winter heating season or inclement weather in the summer grilling season could lower demand for propane.
Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Many of our customers rely on propane primarily as a heating source during the winter. For the year ended December 31, 2013, on a pro forma basis, we sold approximately 61% of our retail, commercial and wholesale propane volumes during the first and fourth quarters of the year.
Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in five of the six states in which we operate our NGL sales business were 21%, 5% and 3% warmer than normal for 2012, 2011 and 2010, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (the "NOAA"). For 2013, the average temperature in the six states in which we operate was consistent with the average temperature measured by the NOAA.
Conversely, our cylinder exchange business experiences higher volumes in the spring and summer, which includes the majority of the grilling season. For the year ended December 31, 2013, on a pro forma basis, we sold approximately 60% of the propane volumes in our cylinder exchange business during the second and third quarters of the year. Sustained periods of poor weather, particularly in the grilling season, can reduce consumers' propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange and our outdoor products.
Sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements and these contracted pricing arrangements will adversely affect our profit margins if they are not immediately hedged with an offsetting propane purchase commitment.
Results of operations related to the retail distribution of propane is primarily based on the cents-per-gallon difference between the sales price we charge our customers and our costs to purchase and deliver propane to our propane distribution locations. We enter into propane sales commitments with a portion of our customers that provide for a contracted price agreement for a specified period of time. The propane cost per gallon is subject to various market conditions and may fluctuate based on changes in demand, supply and other energy commodity prices, such as crude oil and natural gas prices. We employ risk management techniques that attempt to mitigate risks related to the purchasing, storing, transporting and selling of propane. However, sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements. In addition, even upon the expiration of short-term contracts, we may face competitive or relationship pressure to minimize any price increases. Therefore, these commitments expose us to product price risk and reduced profit margins if those transactions are not immediately hedged with an offsetting propane purchase commitment.
High prices for propane can lead to customer conservation and attrition, resulting in reduced demand for our products.
Propane prices are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane commodity market conditions. During periods of high propane costs our selling prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.
We are dependent on certain principal propane suppliers, which increases the risks from an interruption in supply and transportation.
During the year ended December 31, 2013 and the six months ended June 30, 2014, we purchased 55% and 66%, respectively, of our propane needs from four suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from
32
alternative locations might be materially higher and our earnings could be affected. Additionally, in certain areas, based on favorable pricing or the strategic location of certain supply points, a single supplier may provide more than 75% of our propane requirements for that area. Although we have relationships with other suppliers in these areas and have the ability to acquire product elsewhere, in the event of a supply disruption with our primary suppliers in certain regions, we could be forced to purchase propane at a less favorable price and with a higher transportation cost. Accordingly, disruptions in supply in certain areas could also have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Energy efficiency, advances in technology and competition from other energy sources may affect demand for propane and increases in propane prices may cause our residential customers to increase their conservation efforts.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has generally reduced the demand for propane. Propane also competes with other sources of energy such as electricity, natural gas and fuel oil, some of which can be less costly for equivalent energy value. In particular, the gradual expansion of the nation's natural gas distribution systems has increased the availability of affordable natural gas in rural areas, which historically found propane to be the more cost-effective choice. We cannot predict the effect that future conservation measures, technological advances in heating, conservation, energy generation or other devices or the development of alternative energy sources might have on our operations. As the price of propane increases, some of our customers tend to increase their conservation efforts and thereby decrease their consumption of propane.
If the independently owned third-party haulers that we rely upon for the delivery of propane cylinders from our production facilities to certain of our distribution depots do not perform as expected, or if we or these third-party haulers are not able to manage growth effectively, our relationships with our customers may be adversely impacted and our delivery of propane by cylinder exchange may decline.
We rely in part on independently owned third-party haulers to deliver cylinders from our production facilities to certain of our distribution depots. Accordingly, our success depends on our ability to maintain and manage relationships with these third-party haulers. We exercise only limited influence over the resources that the third-party haulers devote to the delivery of cylinders. We could experience a loss of consumer or retailer goodwill if our third-party haulers do not adhere to our quality control and service guidelines or fail to ensure the timely delivery of an adequate supply of propane cylinders to certain of our production depots. In addition, the number of retail locations accepting delivery of our propane by cylinder exchange and, subsequently, the retailer's corresponding sales have historically grown significantly along with the creation of our third-party hauler network. Accordingly, our haulers must be able to adequately service an increasing number of propane cylinder deliveries to our distribution depots so that we can service our retail accounts. If we or our third-party haulers fail to manage the growth of our cylinder exchange operations effectively, our financial results from our delivery of propane by cylinder exchange may be adversely affected.
A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.
Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil supply and logistics and NGL distribution and sales segments. Because we do not attempt to hedge motor fuel price risk, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and weather concerns. Additionally, we may be affected by increases in the cost of materials
33
used to produce portable propane cylinders. As a result, any increases in these prices may adversely affect our profitability and competitiveness.
Our failure or our counterparties' failure to perform on obligations under commodity derivative and financial derivative contracts could have a material adverse effect on our financial condition, results of operations and cash flows.
We enter into in hedging arrangements on a rolling twelve-month basis to manage the cost of propane in our cylinder exchange business. We also may from time to time enter into derivative instruments to hedge our exposure to variable interest rates. Volatility in the oil and gas commodities sector for an extended period of time or intense volatility in the near-term could impair our or our counterparties' ability to meet margin calls, which could cause us or our counterparties to default on commodity and financial derivative contracts. This could have a material adverse effect on our liquidity or our ability to procure product supply at prices reasonable to us or at all.
We are exposed to the credit risks, and certain other risks, of our key customers and other counterparties.
In connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for (i) certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition, (ii) certain matters arising from the pre-closing ownership and operation of assets and (iii) ongoing remediation related to the assets. Our business, results of operations, financial condition and our ability to make cash distributions to our unitholders could be adversely affected in the future if these third parties fail to satisfy an indemnification obligation owed to us.
We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from JP Development, ArcLight Fund V or third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow is dependent, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based in large part on our expectation of ongoing divestitures of midstream energy assets by industry participants, including our affiliates. Subject to the right of first offer granted to us, JP Development and ArcLight Fund V are under no obligation to offer to sell us assets and a material decrease in such divestitures by industry participants would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.
If we are unable to make accretive acquisitions, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from our operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
- •
- mistaken assumptions about volumes, revenue and costs, including operational synergies;
- •
- an inability to secure adequate customer commitments to use the acquired assets or businesses;
- •
- an inability to successfully integrate the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;
34
- •
- the assumption of unknown liabilities;
- •
- limitations on rights to indemnity from the seller;
- •
- unforeseen difficulties operating in new geographic areas and business lines; and
- •
- customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our right of first offer to acquire certain ArcLight assets and all of JP Development's existing and future assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.
Our Right of First Offer Agreement with JP Development and ArcLight Fund V provides us with a right of first offer on (i) JP Development's existing and future assets for a period of five years from the closing of this offering and (ii) ArcLight Fund V's indirect 50% interest in Republic for a period of eighteen months from the closing of this offering. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, JP Development's and ArcLight Fund V's willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and JP Development and ArcLight Fund V are under no obligation to accept any offer that we may choose to make in response to any notice by JP Development or ArcLight of their intent to transfer assets. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any of JP Development's or ArcLight Fund V's assets are offered for sale, and our decision will not be subject to unitholder approval. Please read "Certain Relationships and Related Party Transactions—Agreements With Affiliates in Connection With the Transactions—Right of First Offer Agreement."
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing assets and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
We continuously consider potential acquisitions and opportunities for organic growth projects. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. In addition, a variety of factors
35
beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, changes in key benchmark interest rates, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or the capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our growth strategy, enhance our existing business, complete acquisitions and organic growth projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the crude oil and refined products that we gather, store, transport and handle.
The crude oil and refined products that we gather, store, transport and handle are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our refined products terminals and could require the construction of additional facilities to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws include federal and state laws that impose obligations related to air emissions, regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal, regulate discharges from our facilities into state and federal waters, including wetlands, establish strict liability for releases of oil into waters of the United States, impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities, relate to the protection of endangered flora and fauna and impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, some of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the facilities where any wastes we generate are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Numerous governmental authorities, such as the Environmental Protection Agency (the "EPA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply
36
with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. More stringent laws and regulations may be adopted in the future. We may not be able to recover all or any of these costs from insurance.
Climate change legislation or regulatory initiatives could result in increased operating costs and reduced demand for the services we provide.
On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act ("CAA"). In June 2010, the EPA adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which phases in permitting requirements for stationary sources of GHGs, beginning January 2, 2011. This rule "tailors" these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
37
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production in our areas of operation, which could adversely impact our business and results of operations.
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the crude oil transportation, storage, supply and logistics, refined products terminals and storage and NGL distribution and sales industries, including:
- •
- damage to our facilities, vehicles and equipment caused by hurricanes, tornadoes, floods, fires and other natural
disasters, acts of terrorism and actions by third parties;
- •
- inadvertent damage from construction, vehicles, farm and utility equipment;
- •
- leaks of crude oil, NGLs and other hydrocarbons or losses of crude oil or NGLs as a result of the malfunction of equipment
or facilities;
- •
- ruptures, fires and explosions; and
- •
- other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground storage tanks. In addition, although we are insured for environmental pollution resulting from certain environmental incidents, we may not be insured against all environmental incidents that might occur, some of which may result in toxic tort claims. If a significant incident occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.
38
We are subject to litigation risks that could adversely affect our operating results to the extent not covered by insurance.
Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as NGLs, refined products and crude oil. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers' compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.
Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates are likely to increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at intended levels.
Debt we may incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities.
Upon the closing of this offering, we expect to have approximately $75.0 million of total indebtedness and $153.7 million available for future borrowings under our revolving credit facility. Our future level of debt could have important consequences to us, including the following:
- •
- our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available on favorable terms;
- •
- our funds available for operations, future business opportunities and cash distributions to our unitholders will be
reduced by that portion of our cash flow required to make interest payments on our debt;
- •
- we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
- •
- our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
39
Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to our unitholders and value of our common units.
Our revolving credit facility limits our ability to, among other things:
- •
- incur or guarantee additional debt;
- •
- make distributions on or redeem or repurchase units;
- •
- make certain investments and acquisitions;
- •
- make capital expenditures;
- •
- incur certain liens or permit them to exist;
- •
- enter into certain types of transactions with affiliates;
- •
- merge or consolidate with or into another company; and
- •
- transfer, sell or otherwise dispose of our assets.
Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. For example, for the three months ended June 30, 2014, we were not in compliance with the leverage ratio covenant calculated for the twelve-month rolling period ended June 30, 2014. In addition, if we do not close this offering before November 14, 2014 we will be required to obtain a waiver from the lenders under our revolving credit facility because we anticipate that we will be in violation of the leverage ratio covenant.
The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with, or obtain a waiver of, the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to terminate the remaining commitments under our revolving credit facility and declare the outstanding principal thereunder, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
Cyber-attacks and threats could have a material adverse effect on our operations.
Cyber-attacks may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. We currently are implementing our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material adverse effect on our operations or those of our customers.
The risk of terrorism, political unrest and hostilities in the Middle East or other energy producing regions may adversely affect the economy and our business.
Terrorist attacks, political unrest and hostilities in the Middle East or other energy producing regions may adversely impact the price and availability of crude oil, refined products and NGLs, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil and NGL supplies and markets, and our infrastructure or facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to gather and transport crude oil, refined products and NGLs if our means of transportation
40
become damaged as a result of an attack. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.
The Dodd-Frank Act was signed into law in 2010 and regulates derivative transactions, which include certain instruments used in our risk management activities. Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants, establishment of business conduct standards, recordkeeping and reporting requirements and imposition of position limits. The Dodd-Frank Act and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel and employees.
Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with energy industry experience. Competition for these persons in the energy industry is intense. For instance, given the overall demand for crude oil transportation services, qualified drivers of crude oil gathering and transportation trucks are in high demand. We may be unable to attract and retain enough qualified drivers to effectively service our customers. Additionally, given our size, we may be at a disadvantage, relative to our larger competitors, in the competition to attract and retain such personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including Lonestar, JP Development and ArcLight, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.
Following this offering, CB Capital Holdings II, LLC and JP Energy GP LLC (two entities that are owned and controlled by certain members of management) and Lonestar will own and control our general partner and its non-economic general partner interest in us. In addition, management will own an aggregate 5.0% limited partner interest in us (or a 4.5% limited partner interest in us if the underwriters exercise in full their option to purchase additional common units) and Lonestar will own a 51.2% limited partner interest in us (or a 46.5% limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). Although our general partner has a
41
duty to manage us in a manner that it believes is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owners. Conflicts of interest may arise between CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar, JP Development and ArcLight and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including Lonestar, JP Development and ArcLight, over the interests of our unitholders. These conflicts include, among others, the following:
- •
- neither our partnership agreement nor any other agreement requires CB Capital Holdings II, LLC,
JP Energy GP LLC, Lonestar, JP Development or ArcLight to pursue a business strategy that favors us;
- •
- our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with
contractual standards governing its duties, limiting our general partner's liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might
constitute breaches of fiduciary duty;
- •
- certain officers and directors of our general partner are officers or directors of affiliates of our general partner,
including CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar and JP Development, and also devote significant time to the business of these entities and are
compensated accordingly;
- •
- affiliates of our general partner are not limited in their ability to compete with us and may offer business opportunities
or sell midstream assets to parties other than us, subject to the right of first offer that JP Development and ArcLight Fund V have granted us;
- •
- except in limited circumstances, our general partner has the power and authority to conduct our business without
unitholder approval;
- •
- our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuances of additional
partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
- •
- our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure
is classified as an expansion capital expenditure, which would not reduce our operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can
affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of subordinated
units to convert into common units;
- •
- our general partner will determine which costs incurred by it are reimbursable by us;
- •
- our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose
or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;
- •
- our partnership agreement permits us to classify up to $30.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the incentive distribution rights;
42
- •
- our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any
services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
- •
- our general partner intends to limit its liability regarding our contractual and other obligations;
- •
- our general partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates
if it and its affiliates own more than 80.0% of our outstanding common units;
- •
- our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates,
including (i) the right of first offer granted to us by JP Development and (ii) the performance of one of the truck transportation agreements in our crude oil gathering and
transportation business, each as described in greater detail in "Certain Relationships and Related Party Transactions";
- •
- our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
- •
- our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Duties."
Affiliates of our general partner, including Lonestar, JP Development and ArcLight, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.
Neither our partnership agreement nor any other agreement will prohibit affiliates of our general partner, including Lonestar, JP Development and ArcLight, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, ArcLight Fund V is the majority owner of the general partner of another publicly traded master limited partnership in the midstream segment of the energy industry, which may compete with us in the future. In addition, Lonestar, JP Development, ArcLight and other affiliates of our general partner may acquire, construct or dispose of midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets, subject to the right of first offer that JP Development and ArcLight Fund V, have granted us. As a result, competition from affiliates of our general partner, including Lonestar, JP Development LP and ArcLight, could materially adversely impact our results of operations and distributable cash flow.
43
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of distributable cash flow available to our unitholders.
Other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions, and our general partner has considerable discretion to establish cash reserves that would reduce the amount of available cash we distribute to unitholders.
Generally, our available cash is comprised of cash on hand at the end of a quarter plus cash on hand resulting from any working capital borrowings made after the end of the quarter less cash reserves established by our general partner. Our partnership agreement permits our general partner to establish cash reserves for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements), to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to unitholders. As a result, even when there is no change in the amount of distributable cash flow that we generate, our general partner has considerable discretion to establish cash reserves, which would result in a reduction the amount of available cash we distribute to unitholders. Accordingly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the language in our partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of the General Partner."
44
Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
- •
- whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our
general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard
imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
- •
- our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general
partner so long as it acted in good faith (for additional information related to the meaning of "good faith," please read "Conflicts of Interest and Duties—Duties of the General Partner");
- •
- our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners
resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its
officers and directors, as the case may be, engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
- •
- our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any unitholder or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties."
If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.
In the future, we may acquire or construct assets that are subject to regulation by the Federal Energy Regulatory Commission ("FERC"), and we may enter into leases with, or obtain permits or other authorizations from, the federal government that place citizenship requirements on our investors. In order to avoid (i) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on any assets that are subject to rate regulation by FERC or analogous regulatory body and (ii) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are United States citizens. Rate eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity's
45
owners are subject to such taxation. Please read "Description of the Common Units—Transfer of Common Units." If you are not a person who meets the requirements to be a citizenship eligible holder and a rate eligible holder, you run the risk of having your units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if you are not a person who meets the requirements to be a citizenship eligible holder, you will not be entitled to voting rights. Please read "Our Partnership Agreement—Redemption of Ineligible Holders."
Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our distributable cash flow. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Lonestar, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are controlled by members of our management and by Lonestar. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be reduced because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
Our unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At closing, our general partner and its affiliates will own 56.1% of our common units and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner and its affiliates under our directed unit program). Also, if our general partner is removed without cause during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated
46
units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. "Cause" is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders' dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its non-economic general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of our general partner's members to transfer their membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers of our general partner.
Our general partner may transfer its incentive distribution rights to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its non-economic general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Lonestar or its affiliates, including JP Development, selling or contributing midstream assets to us, as Lonestar and its affiliates would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
You will experience immediate and substantial dilution in pro forma net tangible book value of $14.52 per common unit.
The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $5.48 per unit. Based on an assumed initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $14.52 per common unit. This dilution results primarily because our assets are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."
47
We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our revolving credit facility prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
- •
- our unitholders' proportionate ownership interest in us will decrease;
- •
- the amount of distributable cash flow available for distribution on each unit may decrease;
- •
- because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment
of the minimum quarterly distribution will be borne by our common unitholders will increase;
- •
- the ratio of taxable income to distributions may increase;
- •
- the relative voting strength of each previously outstanding unit may be diminished; and
- •
- the market price of our common units may decline.
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds under our revolving credit facility, from Lonestar or its affiliates or otherwise from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80.0% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 22.1% of our common units (excluding any common units purchased by officers, directors and director nominees of our general partner under our directed unit program). At the end of the subordination period (which could occur as early as September 30, 2015), assuming no additional issuances of common units (other than upon the conversion of the subordinated units) and no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 56.1% of our common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program). For additional information about the call right, please read "Our Partnership Agreement—Limited Call Right."
48
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:
- •
- we were conducting business in a state but had not complied with that particular state's partnership statute; or
- •
- your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.
Please read "Our Partnership Agreement—Limited Liability" for a discussion of the implications of the limitations of liability on a unitholder.
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.
Prior to this offering, there has been no public market for our common units. After this offering, there will be only 13,750,000 publicly traded common units. In addition, affiliates of our general partner, including CB Capital Holdings II, LLC, JP Energy GP LLC and Lonestar, will own 4,025,754 of our common units and 16,427,252 of our subordinated units, representing an aggregate 56.1% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units.
The initial public offering price for the common units offered hereby will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of our common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by other factors, many of which are beyond our control.
49
Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee will have the same rights as our general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."
Our management team does not have experience managing our business as a stand-alone publicly traded partnership, and if they are unable to manage our business as a publicly traded partnership our business may be affected.
Our management team does not have experience managing our business as a publicly traded partnership. Unlike private companies, publicly traded entities are subject to substantial rules and regulations, including rules and regulations promulgated by the SEC and rules governing listed entities on the NYSE. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations will be adversely affected.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
We have been approved to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management—Management of JP Energy Partners LP."
50
We will incur increased costs as a result of being a publicly traded partnership.
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, Sarbanes Oxley and related rules implemented by the SEC and the NYSE have mandated changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make our activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and possibly to result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.
We have included $3.5 million of estimated incremental annual costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this matter.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, the State of Texas currently imposes a franchise tax on the taxable margin of corporations and other entities, including limited partnerships. Imposition of any such taxes may substantially reduce the distributable cash flow available for distribution to you. Therefore, if we
51
were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes. Please read "Material Federal Income Tax Consequences—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders (including holders of our subordinated units) because the costs will reduce our distributable cash flow.
52
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."
Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
An investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.
We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, however, the Treasury
53
Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."
A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and our unitholders, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
54
The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our technical termination for federal income tax purposes.
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in every state in the continental United States. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.
55
We expect to receive net proceeds of approximately $257.1 million from the sale of common units in this offering, based on an assumed initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) after deducting underwriting discounts and structuring fees but before estimated offering expenses. We intend to use these net proceeds as follows:
- •
- pay estimated offering expenses of approximately $2.0 million;
- •
- redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million;
- •
- repay $195.6 million of the debt outstanding under our revolving credit facility; and
- •
- replenish approximately $17.1 million of working capital.
Please read "Prospectus Summary—Recapitalization Transactions and Partnership Structure."
As of August 31, 2014, we had approximately $195.6 million of debt outstanding under our revolving credit facility. Borrowings under our revolving credit facility bear interest at 3.62% and are due on February 19, 2019. Our outstanding indebtedness was incurred to primarily fund third party acquisitions and for general partnership purposes.
Immediately following the repayment of a portion of the outstanding debt under our revolving credit facility with a portion of the net proceeds from this offering, we will borrow approximately $75.0 million thereunder. We will use the proceeds from that borrowing to replenish our working capital.
Prior to the closing of this offering, we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital to our existing partners, pro rata in accordance with their ownership interest in us.
The net proceeds from any exercise by the underwriters of their option to purchase additional common units will be used to redeem a number of common units from our existing partners, pro rata, equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Accordingly, any exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."
An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease by $10.9 million and $14.9 million, respectively, based on an assumed initial public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover of this prospectus. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover of this prospectus, would increase net proceeds to us from this offering by approximately $30.5 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $20.00 per common unit, would decrease the net proceeds to us from this offering by approximately $32.6 million. If the proceeds increase due to a higher initial public offering price then we will distribute those additional proceeds, pro rata, to our existing equityholders. If the proceeds decrease due to a lower initial public offering price, then we will reduce the amount of working capital that will be replenished by an equal amount.
Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Deutsche Bank Securities, Inc. and BMO Capital Markets Corp. are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering. The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Please read "Underwriting."
56
The following table shows:
- •
- our historical cash and cash equivalents and capitalization as of June 30, 2014; and
- •
- our pro forma capitalization as of June 30, 2014, giving effect to the pro forma adjustments described in our unaudited pro forma consolidated financial data included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under "Use of Proceeds" and the other transactions described under "Prospectus Summary—Recapitalization Transactions and Partnership Structure."
This table is derived from, should be read together with and is qualified in its entirety by reference to the audited historical consolidated financial statements and the accompanying notes and the pro forma combined consolidated financial data and accompanying notes included elsewhere in this prospectus.
| |
As of June 30, 2014 | ||||||
|---|---|---|---|---|---|---|---|
| ($ in thousands) |
Historical | Pro Forma | |||||
Cash and cash equivalents |
$ | 1,126 | $ | 108,451 | |||
Debt: |
|||||||
Revolving credit facility(1) |
$ | 181,600 | $ | 75,000 | |||
Other debt(2) |
1,722 | 1,722 | |||||
Total long-term debt (including current maturities) |
$ | 183,322 | $ | 76,722 | |||
Partners' capital: |
|||||||
Series D preferred units |
$ | 40,057 | $ | — | |||
General partner interest |
(12,323 | ) | — | ||||
Class A common units |
394,393 | — | |||||
Class B common units |
10,491 | — | |||||
Class C common units |
72,888 | — | |||||
Common units—Public |
— | 252,366 | |||||
Common units—JP Energy |
— | 70,314 | |||||
Subordinated units |
— | 286,921 | |||||
Total partners' capital |
$ | 505,506 | $ | 609,601 | |||
Total capitalization |
$ | 688,828 | $ | 686,323 | |||
- (1)
- As
of August 31, 2014, we had approximately $195.6 million of indebtedness outstanding under our revolving credit facility.
- (2)
- Consists of other notes payable.
57
Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2014, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $199.6 million, or $5.48 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.
Assumed initial public offering price per common unit |
$ | 20.00 | |||||
Pro forma net tangible book value per unit before the offering(1) |
$ | 2.33 | |||||
Increase in net tangible book value per unit attributable to purchasers in the offering |
$ | 3.15 | |||||
Less: Pro forma net tangible book value per unit after the offering(2) |
5.48 | ||||||
Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)(4) |
$ | 14.52 | |||||
- (1)
- Determined
by dividing the number of units (4,463,502 common units and 18,213,502 subordinated units) to be issued to the general partner and its affiliates
and other investors for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities.
- (2)
- Determined
by dividing the number of units to be outstanding after this offering (18,213,502 total common units and 18,213,502 subordinated units) and the
application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.
- (3)
- If
the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would
equal $15.29 and $13.75, respectively.
- (4)
- Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.
The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates and other investors in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.
| |
Units Acquired | Total Consideration | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ($ in millions) |
Number | % | Amount | % | |||||||||
General partner and its affiliates and other investors(1)(2) |
22,677,004 | 62.0 | % | $ | (39,352,580 | ) | 0.0 | % | |||||
Purchasers in this offering |
13,750,000 | 38.0 | % | $ | 275,000,000 | 100.0 | % | ||||||
Total |
36,427,004 | 100.0 | % | $ | 235,647,420 | 100.0 | % | ||||||
- (1)
- Upon
the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates and other investors will own 4,463,502
common units and 18,213,502 subordinated units.
- (2)
- Assumes the underwriters' option to purchase additional common units is not exercised.
58
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, "Forward-Looking Statements" and "Risk Factors" should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.
For additional information regarding our historical and pro forma results of operations, please refer to our historical consolidated financial statements and accompanying notes and the pro forma combined consolidated financial data and accompanying notes included elsewhere in this prospectus.
Rationale for Our Cash Distribution Policy
Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our general partner has considerable discretion to determine the amount of our available cash each quarter. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. In addition, our general partner has considerable discretion in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:
- •
- Our ability to pay cash distributions will be subject to restrictions on cash distributions under our revolving credit
facility. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our revolving credit facility. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility."
- •
- The amount of cash that we distribute and the decision to make any distribution is determined by our general partner,
taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for
future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate. Any decision
to establish cash reserves made by our general partner in good faith will be binding on our unitholders.
- •
- While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read "Our
59
- •
- Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would
cause our liabilities to exceed the fair value of our assets.
- •
- We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number
of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital
requirements and anticipated cash needs. Our distributable cash flow available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be
reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash
Distributions—Distributions of Available Cash."
- •
- Our ability to make cash distributions to our unitholders depends on the performance of our subsidiaries and their ability
to distribute cash to us. The ability of our subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership
and limited liability company laws and other laws and regulations.
- •
- If and to the extent our available cash materially declines from quarter to quarter, we may elect to reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.
Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval." However, after the subordination period has ended our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, Lonestar and our management will own our general partner and Lonestar will indirectly own an aggregate of approximately 51.2% of our outstanding common units and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner under our directed unit program). Please read "Our Partnership Agreement—Amendment of Our Partnership Agreement."
To the extent that our general partner determines not to distribute the full minimum quarterly distribution with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. Any shortfall in the payment of the minimum quarterly distribution with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period."
Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital
Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. Our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read "Risk Factors—Risks Related to Our Business—Restrictions in our revolving credit facility could adversely affect our
60
business, financial condition, results of operations, ability to make distributions to our unitholders and value of our common units." To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read "Risk Factors—Risks Related to Our Business—Debt we may incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities."
Our Minimum Quarterly Distribution
Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.3250 per unit for each whole quarter, or $1.30 per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy." Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately preceding the indicated distribution date. We do not expect to make distributions for the period that begins on October 1, 2014 and ends on the day prior to the closing of this offering other than the distribution to be made to our existing equityholders in connection with the closing of this offering as described in "Prospectus Summary—Recapitalization Transactions and Partnership Structure" and "Use of Proceeds." We will adjust the amount of our first distribution for the period from the closing of this offering through December 31, 2014 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units and subordinated units to be outstanding immediately after this offering for one quarter and on an annualized basis, assuming no exercise by the underwriters of their option to purchase additional common units, is summarized in the following table:
| |
|
Minimum Quarterly Distributions | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Number of Units | One Quarter | Annualized (Four Quarters) |
|||||||
Common units held by Public |
13,750,000 | $ | 4,468,750 | $ | 17,875,000 | |||||
Common units held by Lonestar |
3,667,305 | 1,191,874 | 4,767,497 | |||||||
Common units held by Management |
358,449 | 116,496 | 465,983 | |||||||
Common units held by Other Investors |
437,748 | 142,268 | 369,073 | |||||||
Subordinated units held by Lonestar |
14,964,588 | 4,863,491 | 19,453,964 | |||||||
Subordinated units held by Other Investors |
1,786,250 | 580,531 | 2,322,125 | |||||||
Subordinated units held by Management |
1,462,664 | 475,366 | 1,901,463 | |||||||
Total |
36,427,004 | $ | 11,838,776 | $ | 47,355,105 | |||||
Our general partner will hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.37375 per unit per quarter.
During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period." We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter.
Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described
61
above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in "good faith," our general partner must believe that the determination is in the best interests of our partnership. Please read "Conflicts of Interest and Duties."
The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.
Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels." The minimum quarterly distribution will also automatically be adjusted in connection with the resetting of the target distribution levels related to our general partner's incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.30 per unit for the twelve months ending September 30, 2015. In those sections, we present two tables:
- •
- "Unaudited Combined Pro Forma Distributable Cash Flow," in which we present the amount of cash we would have had available
for distribution on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, derived from our unaudited pro forma financial data that is included
in this prospectus, as adjusted to give pro forma effect to this offering and the related recapitalization transactions; and
- •
- "Estimated Distributable Cash Flow," in which we provide our estimated forecast of our ability to generate sufficient distributable cash flow for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2015.
Unaudited Combined Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013 and the Twelve Months Ended June 30, 2014
If we had completed this offering and the other transactions contemplated by this prospectus on January 1, 2013, our unaudited combined pro forma distributable cash flow for the year ended December 31, 2013 would have been approximately $24.3 million. This amount would have been sufficient to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $23.1 million for the year ended December 31, 2013. If we had completed this offering and the other transactions contemplated by this prospectus on July 1,
62
2013, our unaudited combined pro forma distributable cash flow for the twelve months ended June 30, 2014 would have been approximately $14.4 million. This amount would have been sufficient to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $33.0 million for the twelve months ended June 30, 2014.
Our unaudited combined pro forma distributable cash flow for the year ended December 31, 2013 and the twelve months ended June 30, 2014 takes into account $3.5 million of incremental annual general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental annual general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental annual general and administrative expenses related to being a publicly traded partnership include expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation. These expenses are not reflected in our historical financial statements or our unaudited pro forma consolidated financial statements included elsewhere in this prospectus.
We based the pro forma adjustments on currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering been completed as of the date indicated. In addition, distributable cash flow is primarily a cash accounting concept, while our unaudited pro forma consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we completed this offering on the dates indicated.
The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, the amount of distributable cash flow that would have been available for distribution to our unitholders, assuming that this offering had been completed at the beginning of each such period. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.
63
JP Energy Partners LP
Unaudited Combined Pro Forma Distributable Cash Flow
| ($ in millions, except per unit data) |
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
|||||
|---|---|---|---|---|---|---|---|
Total revenue |
$ | 2,105.2 | $ | 1,983.2 | |||
Costs and expenses: |
|||||||
Cost of sales, excluding depreciation and amortization |
1,964.6 | 1,843.9 | |||||
Operating expenses |
63.0 | 69.7 | |||||
General and administrative(1) |
45.7 | 48.9 | |||||
Depreciation and amortization |
36.5 | 41.5 | |||||
Loss on disposal of assets |
1.5 | 1.1 | |||||
Total operating expenses |
2,111.3 | 2,005.1 | |||||
Operating income (loss) |
(6.1 | ) | (21.9 | ) | |||
Other income (expense): |
|||||||
Interest expense |
(4.7 | ) | (4.9 | ) | |||
Other income (expense), net |
0.7 | 1.0 | |||||
Loss from continuing operations before income tax: |
(10.1 | ) | (25.8 | ) | |||
Income tax expense(2) |
(0.2 | ) | (0.1 | ) | |||
Pro forma net income (loss) from continuing operations(3) |
(10.3 | ) | (25.9 | ) | |||
Add: |
|||||||
Depreciation and amortization |
36.5 | 41.5 | |||||
Interest expense |
4.7 | 4.9 | |||||
Discontinued operations(4) |
2.0 | 1.4 | |||||
Unit-based compensation |
0.9 | 1.2 | |||||
Loss on disposal of assets |
1.5 | 1.1 | |||||
Total gain on commodity derivative contracts |
(0.9 | ) | (1.5 | ) | |||
Net cash receipts (payments) for commodity derivatives settled during the period |
(0.2 | ) | 0.9 | ||||
Income tax expense(2) |
0.2 | 0.1 | |||||
Transaction costs and other non-cash items |
1.1 | 0.7 | |||||
Pro forma Adjusted EBITDA(5) |
35.5 | 24.4 | |||||
Less: |
|||||||
Incremental general and administrative expenses of being a publicly traded partnership(6) |
3.5 | 3.5 | |||||
Cash interest paid, net of interest income(7) |
4.1 | 3.9 | |||||
Cash income taxes paid(2) |
0.1 | 0.2 | |||||
Expansion capital expenditures(8) |
277.4 | 265.4 | |||||
Maintenance capital expenditures(8) |
3.5 | 2.4 | |||||
Add: |
|||||||
Capital contributions and borrowings to fund expansion capital expenditures |
277.4 | 265.4 | |||||
Pro forma distributable cash flow |
$ | 24.3 | $ | 14.4 | |||
Implied cash distribution at the minimum quarterly distribution rate: |
|||||||
Annualized minimum quarterly distribution per unit |
$ | 1.30 | $ | 1.30 | |||
Distributions to public common unitholders |
17.9 | 17.9 | |||||
Distributions to Lonestar—common units |
4.8 | 4.8 | |||||
Distributions to Lonestar—subordinated units |
19.5 | 19.5 | |||||
Distributions to Management—common units |
0.5 | 0.5 | |||||
Distributions to Management—subordinated units |
1.9 | 1.9 | |||||
Distributions to Other Investors—common units |
0.5 | 0.5 | |||||
Distributions to Other Investors—subordinated units |
2.3 | 2.3 | |||||
Total distributions to unitholders(9) |
$ | 47.4 | $ | 47.4 | |||
Excess (shortfall) of pro forma distributable cash flow over the aggregate annualized minimum quarterly distribution |
$ | (23.1 | ) | $ | (33.0 | ) | |
Percent of minimum quarterly distribution payable to common unitholders |
100 | % | 61 | % | |||
Percent of minimum quarterly distribution payable to subordinated unitholders |
2.6 | % | — | % | |||
- (1)
- Includes segment general and administrative expenses of $16.2 million and $18.6 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, which includes items such as
64
management, sales and regional office expenses that are directly related to the operations of our business segments. Also includes corporate general and administrative expenses of $29.5 million and $30.3 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, which includes professional fees of $14.1 million and $12.7 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur during the twelve months ending September 30, 2015. The professional fees incurred during the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily related to (i) audits of our 2011 and 2012 financial statements as well as reviews of our quarterly financial statements for the three months ended March 31, 2013 and June 30, 2013, (ii) audits related to several significant acquisitions that took place during the period, (iii) valuation services associated with our acquisitions in 2011 and 2012 and (iv) contract labor costs in our accounting group to manage additional accounting and financial reporting matters.
- (2)
- Represents
a 1.0% state tax on gross margin, which is generally defined as total revenue minus cost of sales, from our operations in Texas.
- (3)
- Pro
forma net income (loss) for the year ended December 31, 2013 gives effect to the pro forma adjustments reflected in our unaudited pro forma
combined consolidated financial statements included elsewhere in this prospectus.
- (4)
- In
June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
- (5)
- Adjusted
EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly
comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP
Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of
Operations—How We Evaluate Our Operations."
- (6)
- Represents
estimated cash expense associated with being a publicly traded partnership, such as expenses associated with SEC reporting requirements, tax
return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent
fees, incremental officer and director liability expenses and director compensation.
- (7)
- Represents
"Interest expense" adjusted to exclude amortization of deferred financing costs.
- (8)
- Historically,
we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Under our partnership agreement,
maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will
increase our operating income or operating capacity over the long term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the
existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast,
expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or
facilities. For the year ended December 31, 2013, our pro forma capital expenditures inclusive of acquisitions totaled $280.9 million. We estimate that $3.5 million of our pro
forma capital expenditures were maintenance capital expenditures and $277.4 million were expansion capital expenditures, of which $44.2 million were unrelated to acquisitions and
$233.2 million were acquisition-related. For the twelve months ended June 30, 2014, our pro forma capital expenditures inclusive of acquisitions totaled $267.8 million. We
estimate that $2.4 million of our pro forma capital expenditures were maintenance capital expenditures and $265.4 million were expansion capital expenditures, of which
$33.1 million were unrelated to acquisitions and $232.3 million were acquisition-related. For a discussion of our maintenance capital expenditures and our expansion capital expenditures,
please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."
- (9)
- Totals may not sum due to rounding.
Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2015
We forecast that our estimated distributable cash flow for the twelve months ending September 30, 2015 will be approximately $56.8 million. This amount would exceed by $9.4 million the amount needed to pay the aggregate annualized minimum quarterly distribution of $47.4 million on all of our units for the twelve months ending September 30, 2015. To the extent we experience a shortfall in distributable cash flow in any particular quarter, including during the twelve months ending September 30, 2015, our partnership agreement will allow us to use cash on hand or borrow funds under our credit facility to cover such a shortfall in order to pay our minimum quarterly distribution.
65
We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated distributable cash flow and related assumptions set forth below to supplement our historical consolidated financial statements and our unaudited pro forma consolidated financial statements in support of our belief that we will generate sufficient cash to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus, our unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "—Assumptions and Considerations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient distributable cash flow to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance with respect thereto. The report of our independent registered public accounting firm included in this prospectus relates to our historical consolidated financial statements. It does not extend to the prospective financial information and should not be read to do so.
When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated distributable cash flow for the twelve months ending September 30, 2015.
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe we will have sufficient distributable cash to allow us to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015 should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.
66
JP Energy Partners LP
Estimated Distributable Cash Flow
| |
Three Months Ending | |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Twelve Months Ending September 30, 2015 |
|||||||||||||||
| ($ in millions, except per unit amounts) |
December 31, 2014 |
March 31, 2015 |
June 30, 2015 |
September 30, 2015 |
||||||||||||
Revenue: |
||||||||||||||||
Crude oil pipeline and storage |
$ | 31.0 | $ | 34.9 | $ | 44.9 | $ | 62.8 | $ | 173.6 | ||||||
Crude oil supply and logistics |
475.9 | 565.3 | 628.8 | 647.3 | 2,317.3 | |||||||||||
Refined products terminaling and storage |
7.9 | 9.7 | 6.0 | 5.5 | 29.1 | |||||||||||
NGL distribution and sales |
54.8 | 66.1 | 54.5 | 52.7 | 228.1 | |||||||||||
Total operating revenue |
569.6 | 676.0 | 734.2 | 768.3 | 2,748.1 | |||||||||||
Operating expenses: |
||||||||||||||||
Cost of sales, excluding depreciation and amortization |
530.2 | 631.0 | 686.5 | 719.2 | 2,566.9 | |||||||||||
Operating expenses |
16.5 | 18.4 | 19.7 | 19.0 | 73.6 | |||||||||||
General and administrative(1) |
9.8 | 11.2 | 9.8 | 10.0 | 40.8 | |||||||||||
Depreciation and amortization |
11.2 | 12.2 | 13.4 | 13.6 | 50.4 | |||||||||||
Total operating expenses |
567.7 | 672.8 | 729.4 | 761.8 | 2,731.7 | |||||||||||
Operating income |
1.9 | 3.2 | 4.8 | 6.5 | 16.4 | |||||||||||
Interest expense(2) |
1.2 | 1.4 | 1.8 | 2.0 | 6.4 | |||||||||||
Other expense |
0.6 | 0.6 | 0.6 | 0.6 | 2.4 | |||||||||||
Income tax expense(3) |
0.1 | 0.1 | 0.1 | 0.1 | 0.4 | |||||||||||
Net income |
— | 1.1 | 2.3 | 3.8 | 7.2 | |||||||||||
Add: |
||||||||||||||||
Depreciation and amortization |
11.2 | 12.2 | 13.4 | 13.6 | 50.4 | |||||||||||
Interest expense, net |
1.2 | 1.4 | 1.8 | 2.0 | 6.4 | |||||||||||
Income tax expense(3) |
0.1 | 0.1 | 0.1 | 0.1 | 0.4 | |||||||||||
Non-cash charges |
0.6 | 0.6 | 0.6 | 0.6 | 2.4 | |||||||||||
Adjusted EBITDA(4) |
13.1 | 15.4 | 18.2 | 20.1 | 66.8 | |||||||||||
Less: |
||||||||||||||||
Cash interest paid, net of interest income(5) |
1.1 | 1.2 | 1.6 | 1.7 | 5.6 | |||||||||||
Expansion capital expenditures(6) |
34.9 | 44.8 | 24.3 | 4.7 | 108.7 | |||||||||||
Maintenance capital expenditures(6) |
0.7 | 0.9 | 0.9 | 1.5 | 4.0 | |||||||||||
Income tax expense(3) |
0.1 | 0.1 | 0.1 | 0.1 | 0.4 | |||||||||||
Add: |
||||||||||||||||
Borrowings to fund expansion capital expenditures |
34.9 | 44.8 | 24.3 | 4.7 | 108.7 | |||||||||||
Estimated distributable cash flow |
$ | 11.2 | $ | 13.2 | $ | 15.6 | $ | 16.8 | $ | 56.8 | ||||||
Implied cash distribution at the minimum quarterly distribution rate: |
||||||||||||||||
Annualized minimum quarterly distribution per unit |
$ | 0.3250 | $ | 0.3250 | $ | 0.3250 | $ | 0.3250 | $ | 1.30 | ||||||
Distributions to public common unitholders |
4.5 | 4.5 | 4.5 | 4.5 | 17.9 | |||||||||||
Distributions to Lonestar—common units |
1.2 | 1.2 | 1.2 | 1.2 | 4.8 | |||||||||||
Distributions to Lonestar—subordinated units |
4.9 | 4.9 | 4.9 | 4.9 | 19.5 | |||||||||||
Distributions to Management—common units |
0.1 | 0.1 | 0.1 | 0.1 | 0.5 | |||||||||||
Distributions to Management—subordinated units |
0.4 | 0.4 | 0.4 | 0.4 | 1.9 | |||||||||||
Distributions to Other Investors—common units |
0.1 | 0.1 | 0.1 | 0.1 | 0.5 | |||||||||||
Distributions to Other Investors—subordinated units |
0.6 | 0.6 | 0.6 | 0.6 | 2.3 | |||||||||||
Total distributions to unitholders(7) |
11.8 | 11.8 | 11.8 | 11.8 | 47.4 | |||||||||||
Excess (shortfall) of distributable cash flow over the aggregate annualized minimum quarterly distribution |
(0.6 | ) | 1.4 | 3.8 | 5.0 | 9.4 | ||||||||||
Percent of minimum quarterly distribution payable to common unitholders |
100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||
Percent of minimum quarterly distribution payable to subordinated unitholders |
90 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||
- (1)
- Includes estimated annual incremental cash expense associated with being a publicly traded partnership of approximately $3.5 million, including costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.
67
- (2)
- Assumes
an aggregate of $152.8 million of average borrowings over the twelve months ending September 30, 2015, bearing interest at a
weighted-average rate of approximately 2.88%. This rate is based on a forecast of LIBOR and prime rates during the period. The $6.4 million of interest expense that we expect to incur during
the twelve months ending September 30, 2015 relates to $5.3 million of interest on our expected revolving credit facility borrowings, unused commitment fees and letters of credit fees,
$0.8 million of amortization of deferred financing costs and $0.3 million of interest on our other debt.
- (3)
- Represents
a 1.0% state tax on gross margin, which is generally defined as total revenue minus cost of sales, from our operations in Texas.
- (4)
- Adjusted
EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly
comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP
Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of
Operations—How We Evaluate Our Operations."
- (5)
- Represents
"Interest expense" adjusted to exclude amortization of deferred financing costs.
- (6)
- Historically,
we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Under our partnership agreement,
maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will
increase our operating income or operating capacity over the long term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the
existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast,
expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or
facilities. For a discussion of our maintenance capital expenditures and our expansion capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash
Distributions—Capital Expenditures."
- (7)
- Totals may not sum due to rounding.
Assumptions and Considerations
Based on a number of specific assumptions, we believe our estimated distributable cash flow for the twelve months ending September 30, 2015 will be $56.8 million, compared to $24.3 million during the pro forma year ended December 31, 2013 and $14.4 million during the pro forma twelve months ended June 30, 2014. Because we believe it is not reasonably possible to forecast gains or losses on commodity derivative contracts and selected charges or any unusual or non-recurring costs or gains for future periods, we have assumed none for the twelve months ending September 30, 2015. Our estimate does not assume any incremental revenues, expenses or other costs associated with acquisitions of businesses, but does include identified organic growth opportunities as described below.
General Considerations
Substantially all of the anticipated increase in our estimated distributable cash flow for the twelve months ending September 30, 2015, compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, is primarily attributable to:
- •
- acquisitions and organic growth projects that have recently been commenced or placed into service but which were either
not included or only partially included in our results for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014,
including:
- •
- a full year of operations on our Silver Dollar Pipeline System, which was placed into service in April 2013;
- •
- growth in our crude oil supply and logistics segment, primarily from expanding our business in the Permian Basin in
January 2014;
- •
- the addition of at-the-rack ethanol blending capabilities at our refined products terminal in North Little Rock, Arkansas in March 2014 and the addition of vapor recovery units at both of our refined products terminals in the fourth quarter of 2013; and
68
- •
- the expansion of our cylinder exchange business into all 48 states in the continental United States in the first
quarter of 2014, including the addition of a new three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to all of their gas stations
in California, Oregon and Washington;
- •
- other pending acquisitions and organic growth initiatives which we expect to be consummated or placed into service in the
near-term and included in our operations and results for the forecast period, including:
- •
- the addition of ethanol blending activities at our refined products terminal in Caddo Mills, Texas and butane blending
capabilities at our refined products terminal in North Little Rock, Arkansas;
- •
- expansion projects on our Silver Dollar Pipeline System and new volume commitments from third party customers; and
- •
- the procurement of additional large-volume or national sales contracts as a result of the national expansion of our
cylinder exchange business; and
- •
- a reduction in general and administrative expenses due to approximately $14.1 million and $12.7 million of
professional fees incurred during the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, a significant portion of which we do not
expect to incur during the twelve month period ending September 30, 2015, related to:
- •
- audits of our 2011 and 2012 financial statements as well as reviews of our quarterly financial statements for the three
months ended March 31, 2013 and June 30, 2013;
- •
- audits related to several significant acquisitions which took place during the period;
- •
- valuation services associated with our acquisitions in 2011 and 2012; and
- •
- contract labor costs due to an increase in personnel in our accounting group to manage additional accounting and financial reporting matters.
While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations and any assumptions not discussed were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There likely will be differences between our forecast and our actual results and those differences could be material. If the forecast is not achieved, we may not be able to make distributions on our units at the minimum quarterly distribution rate or at all.
Commodity Price Volatility
We are exposed to volatility in crude oil, refined products and NGL commodity prices. We manage such exposure through the structure of our sales and supply contracts and through a managed hedging program. As a result, our forecast is not contingent on a particular set of assumptions regarding commodity prices. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk."
Revenues, Cost of Sales and Adjusted Gross Margin
We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gains (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period). Because we believe it is not reasonably possible to forecast unrealized gains or losses on derivatives for future periods, we have assumed none for the twelve months ending September 30, 2015.
69
We view adjusted gross margin as an important measure of our performance and operations because it provides a meaningful comparison of the financial performance of our business segments without the impact of changes in commodity prices between the pro forma and forecast periods, as these changes generally have similar and offsetting impacts on both revenues and cost of sales, excluding depreciation and amortization.
Adjusted gross margin is a supplemental financial measure which is not presented in accordance with GAAP. We believe that the presentation of adjusted gross margin in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to adjusted gross margin is operating income (loss). Adjusted gross margin should not be considered an alternative to operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. For a reconciliation of adjusted gross margin to operating income (loss), please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."
We estimate that our adjusted gross margin will be $181.2 million for the twelve months ending September 30, 2015, compared to $139.5 million for the pro forma year ended December 31, 2013 and $139.0 million for the pro forma twelve months ended June 30, 2014. Our forecasted volumes have been estimated for each of our segments based on our pro forma historical volumes and take into consideration contracts with third parties, as well as our organic growth initiatives. Our estimated adjusted gross margin assumes a consistent renewal rate by our customers with respect to these contracts.
Crude Oil Pipelines and Storage
We estimate that $41.3 million of our total adjusted gross margin will be generated from our crude oil pipelines and storage segment for the twelve months ending September 30, 2015, compared to $19.5 million for the pro forma year ended December 31, 2013 and $24.6 million for the pro forma twelve months ended June 30, 2014. The following table compares our total crude oil pipelines and storage revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.
| |
Pro Forma | Forecasted | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
($ in millions, unless otherwise noted)
|
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
Twelve Months Ending September 30, 2015 |
|||||||
Financial data: |
||||||||||
Revenues |
$ | 28.4 | $ | 61.6 | $ | 173.6 | ||||
Cost of sales, excluding depreciation and amortization(1) |
8.9 | 37.0 | 132.3 | |||||||
Adjusted gross margin |
19.5 | 24.6 | 41.3 | |||||||
Operational data: |
||||||||||
Average daily pipeline throughput (barrels per day)(2) |
8,885 | 15,178 | 55,091 | |||||||
- (1)
- Includes
intersegment cost of sales, excluding depreciation and amortization, of $5.6 million, $30.8 million and $120.5 million for the
pro forma year ended December 31, 2013, twelve months ended June 30, 2014 and twelve months ending September 30, 2015, respectively, which were eliminated upon consolidation.
- (2)
- The Silver Dollar Pipeline System was placed into service in April 2013.
The anticipated increase in adjusted gross margin in our crude oil pipelines and storage segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and pro forma twelve months ended June 30, 2014 relates primarily to (i) the additional amount of time the Silver Dollar Pipeline System will be fully operational in the forecast
70
period, (ii) higher anticipated pipeline throughput from an existing customer and (iii) the expansion of our pipeline system, which is currently underway.
We expect a substantial increase in daily pipeline throughput for the twelve months ending September 30, 2015 compared to the year ended December 31, 2013 and the twelve months ended June 30, 2014 because the Silver Dollar Pipeline System will be fully operating throughout the entire forecast period.
We believe that there will be increased production in the areas we serve. We believe we will be able to increase volumes under our existing long-term agreements, which contain acreage dedications or minimum volume commitments, due to the anticipated increase in drilling activity in the Southern Wolfcamp and because an existing customer amended its long-term agreement with us in March 2014 to substantially increase its committed volumes.
This contract amendment and other anticipated commercial opportunities in the Southern Wolfcamp have enabled us to undertake expansion projects which we believe will further increase daily pipeline throughput during the twelve months ending September 30, 2015. These expansion projects involve the construction of approximately 30 miles of additional pipeline, including an interconnection to a second long-haul transportation pipeline expected to be completed in the fourth quarter of 2014. We believe this will significantly increase the Silver Dollar Pipeline System's gathering footprint and take-away capacity and allow us to obtain new volume commitments, including some from existing customers in our crude oil supply and logistics segment.
We have forecast an adjusted gross margin in our crude oil storage business that is consistent with our results for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014.
Crude Oil Supply and Logistics
We estimate that $28.5 million of our total adjusted gross margin, or $1.15 per barrel sold, will be generated from our crude oil supply and logistics segment for the twelve months ending September 30, 2015, compared to $26.3 million, or $1.35 per barrel sold, for the pro forma year ended December 31, 2013 and $19.5 million, or $1.09 per barrel sold, for the pro forma twelve months ended June 30, 2014. During the twelve months ending September 30, 2015, we estimate that our average barrels sold will be 68,095 barrels per day compared to 53,471 and 49,027 barrels per day for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively. This increase is primarily due to an expansion of our operations in other geographic regions such as the Permian Basin, Mid-Continent and Eagle Ford shale.
71
The following table compares our total crude oil supply and logistics revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.
| |
Pro Forma | Forecasted | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in millions, unless otherwise noted) |
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
Twelve Months Ending September 30, 2015 |
|||||||
Financial data: |
||||||||||
Revenues(1) |
$ | 1,878.5 | $ | 1,729.5 | $ | 2,437.8 | ||||
Cost of sales, excluding depreciation and amortization |
1,852.2 | 1,710.3 | 2,409.3 | |||||||
Adjusted gross margin |
26.3 | 19.5 | (2) | 28.5 | ||||||
Operational data: |
||||||||||
Average barrels sold per day |
53,471 | 49,027 | 68,095 | |||||||
Adjusted gross margin per barrel |
$ | 1.35 | $ | 1.09 | $ | 1.15 | ||||
- (1)
- Includes
intersegment revenues of $5.6 million, $30.8 million and $120.5 million for the pro forma year ended December 31, 2013,
twelve months ended June 30, 2014 and twelve months ending September 30, 2015, respectively, which were eliminated upon consolidation.
- (2)
- Excludes non-cash expense of $0.3 million.
We believe that we will be able to meet the anticipated increase in demand for our crude oil supply and logistics services through the expansion of our operations into the Eagle Ford shale during the second quarter of 2014, expected growth in sales volumes in the Permian Basin from the planned expansion of our Silver Dollar Pipeline System during the forecast period and our management's experience and customer relationships. The increases in sales volumes are partially offset by an expected decrease in sales volumes in the Mid-Continent region from increased competition. However, we expect the growth in sales volumes in the Eagle Ford shale and Permian Basin to significantly offset any decrease in sales volumes in the Mid-Continent region. We have forecast a reduction in adjusted gross margin per barrel due to our expectation of increased competition in the Mid-Continent region and the assumption that our blending activities will generate lower margins as compared to the pro forma year ended December 31, 2013.
Refined Products Terminals and Storage
We estimate that $17.2 million of our total adjusted gross margin, or $0.017 per gallon of throughput, will be generated from our refined products terminals and storage segment for the twelve months ending September 30, 2015, compared to approximately $19.3 million, or $0.018 per gallon of throughput, for the pro forma year ended December 31, 2013 and approximately $18.9 million, or $0.018 per gallon of throughput, for the pro forma twelve months ended June 30, 2014. During the twelve months ending September 30, 2015, we estimate that our refined products terminals throughput will be 2.7 million gallons per day compared to 2.9 million gallons per day for the pro forma year ended December 31, 2013 and 2.8 million gallons per day for the pro forma twelve months ended June 30, 2014.
72
The following table compares our total refined products terminals and storage revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.
| |
Pro Forma | Forecasted | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in millions, unless otherwise noted) |
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
Twelve Months Ending September 30, 2015 |
|||||||
Financial data: |
||||||||||
Revenues |
$ | 24.0 | $ | 24.8 | $ | 29.1 | ||||
Cost of sales, excluding depreciation and amortization |
4.7 | 5.9 | 11.9 | |||||||
Adjusted gross margin |
19.3 | 18.9 | 17.2 | |||||||
Operational data: |
||||||||||
Throughput (Mgal/d) |
2,901 | 2,834 | 2,713 | |||||||
Adjusted gross margin per gallon |
$ | 0.018 | $ | 0.018 | $ | 0.017 | ||||
The anticipated decrease in adjusted gross margin in our refined products terminals and storage segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily relates to an expected reduction in revenues from product sales. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control processes at our refined products terminal in North Little Rock, Arkansas were resulting in excessive product gains for JP Energy. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. As a result, we believe it is reasonably likely that the new processes and procedures that we are undertaking will result in a decrease in revenues from product sales in our refined products terminals and storage segment in future periods relative to historical periods, although this reduction may be partially offset by an operational excellence initiative that we are undertaking at both of our refined products terminals.
NGL Distribution and Sales
We estimate that $94.2 million of our total adjusted gross margin, or $1.26 per gallon of NGL sold, will be generated in our NGL distribution and sales segment for the twelve months ending September 30, 2015, compared to $74.4 million, or $1.13 per gallon of NGL sold, for the pro forma year ended December 31, 2013 and $76.0 million, or $1.10 per gallon of NGL sold, for the pro forma twelve months ended June 30, 2014. We expect an increase in adjusted gross margin per gallon of NGL sold for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily due to a greater percentage of volumes sold in our cylinder exchange business, which generates a higher adjusted gross margin per gallon.
73
The following table compares our total NGL distribution and sales revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.
| |
Pro Forma | Forecasted | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in millions, unless otherwise noted) |
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
Twelve Months Ending September 30, 2015 |
|||||||
Financial data: |
||||||||||
Revenues |
$ | 179.9 | $ | 198.1 | $ | 228.1 | ||||
Cost of sales, excluding depreciation and amortization |
104.4 | 121.5 | 133.9 | |||||||
Adjusted gross margin |
74.4 | (1) | 76.0 | (2) | 94.2 | |||||
Operational data: |
||||||||||
NGL and refined product sales (gallons per day)(3) |
180,850 | 189,059 | 205,446 | |||||||
Adjusted gross margin per gallon |
$ | 1.13 | $ | 1.10 | $ | 1.26 | ||||
- (1)
- Excludes
total gain from commodity derivative contracts and net cash payments for commodity derivatives settled during the period of $0.9 million and
$0.2 million, respectively.
- (2)
- Excludes
total gain from commodity derivative contracts and net cash receipts for commodity derivatives settled during the period of $1.5 million and
$0.9 million, respectively.
- (3)
- Includes gasoline and diesel gallons sold primarily to our oilfield services and agricultural customers.
The anticipated increase in adjusted gross margin in our NGL distribution and sales segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily relates to our assumption that the volume of NGLs sold will increase by 9.0 million gallons for the twelve months ending September 30, 2015, or 13.6%, compared to the pro forma year ended December 31, 2013 and by 6.0 million gallons, or 8.6%, compared to the pro forma twelve months ended June 30, 2014, due to increased activity from our cylinder exchange distribution network related to our national expansion. We recently completed the expansion of our cylinder exchange business into all 48 states in the continental United States through the construction of two new production facilities and associated distribution depots serving Arizona, California and Utah. We believe this expansion will provide us with economies of scale and significant cost savings in product procurement, transportation and general administration. As a result of this expansion, we were successful in obtaining a new, three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to their gas stations in California, Oregon and Washington. We believe that we will be able to add additional large-volume or national accounts due to our ability to provide services nationwide and have assumed in this forecast that we do so.
Operating Expenses
Our operating expenses include payroll, wages, utility costs, fleet costs, repairs and maintenance costs, rent, fuel, insurance premiums, taxes and other operating costs. We estimate that operating expenses for the twelve months ending September 30, 2015 will be $73.6 million, compared to $63.0 million for the pro forma year ended December 31, 2013 and $69.7 million for the pro forma twelve months ended June 30, 2014. The $10.6 million increase in our operating expenses for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 is due to the following:
- •
- a $0.3 million increase in our crude oil pipelines and storage segment primarily due to the growth of the Silver Dollar Pipeline System;
74
- •
- a $1.0 million increase in our refined products terminals and storage segment as a result of an increase in
personnel expense;
- •
- a $9.8 million increase in our NGL distribution and sales segment as a result of (i) additional costs related to
new large-volume or national accounts we expect to enter into as a result of our recent national expansion as well as (ii) other organic growth projects in our cylinder exchange business;
partially offset by
- •
- a $0.5 million decrease in our crude oil supply and logistics segment primarily due to a reduction in fleet maintenance.
The $3.9 million increase in our operating expenses for the twelve months ending September 30, 2015 compared to the pro forma twelve months ended June 30, 2014 is due to the following:
- •
- a $0.8 million increase in our refined products terminals and storage segment as a result of an increase in
personnel expense;
- •
- a $5.8 million increase in our NGL distribution and sales segment as a result of (i) additional costs
related to new large-volume or national accounts we expect to enter into as a result of our recent national expansion as well as (ii) other organic growth projects in our cylinder exchange
business; offset by
- •
- a $2.7 million decrease in operating expenses at our North Little Rock, Arkansas refined products terminal. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal under-delivered refined products to its customers and consequently, recognized excessive gains on refined products generated during the terminal's normal terminal and storage process. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. We estimated the volume of refined products to be returned to customers of approximately 24,000 barrels, which amounts to an estimated value of $2.7 million as of June 30, 2014. Accordingly, we recorded this charge to operating expenses during the pro forma twelve months ended June 30, 2014 and will update the estimated accrual each reporting period based on changes in estimate related to volumes returned, market prices and other changes.
In addition, our pro forma results for the year ended December 31, 2013 and the twelve months ended June 30, 2014 do not include a full year of expense for two individually insignificant acquisitions made in our NGL distribution and sales segment in the second half of 2013.
General and Administrative Expenses
Our general and administrative expenses includes payroll and office expenses, professional fees and insurance costs. We estimate that general and administrative expenses for the twelve months ending September 30, 2015 will be $40.8 million, compared to $45.7 million for the pro forma year ended December 31, 2013 and $48.9 million for the pro forma twelve months ended June 30, 2014. Corporate costs are expected to comprise approximately $22.6 million of general and administrative expenses for the twelve months ending September 30, 2015 compared to approximately $29.5 million of general and administrative expenses for the pro forma year ended December 31, 2013 and approximately $30.3 million for the pro forma twelve months ended June 30, 2014. The remaining amounts included in general and administrative expenses include items such as management, sales and regional office expenses that are directly related to the operations of our business segments. The $4.9 million decrease in our general and administrative expenses compared to the pro forma year ended December 31, 2013 is due to the following:
- •
- a $12.5 million decrease in professional fees related to the commencement of our initial public offering during the pro forma year ended December 31, 2013; partially offset by
75
- •
- a $3.5 million anticipated increase of incremental expenses of being a publicly traded partnership, which includes
costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance,
stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.
- •
- a $2.3 million increase in corporate personnel expense as our pro forma results for the year ended
December 31, 2013 do not include a full year of expense from additional headcount made during the second half of 2013 to support the growth of our business;
- •
- a $2.5 million increase in our NGL distribution and sales segment as a result (i) growth projects in our cylinder exchange business and (ii) our pro forma results for the year ended December 31, 2013 do not include a full year of expense from two individually insignificant acquisitions made in the second half of 2013.
The $8.1 million decrease in our general and administrative expenses compared to the pro forma twelve months ended June 30, 2014 is due to the following:
- •
- an $11.1 million decrease in professional fees related to the commencement of our initial public offering during
the pro forma year twelve months ended June 30, 2014; partially offset by
- •
- a $3.5 million anticipated increase of incremental expenses of being a publicly traded partnership as discussed above.
Adjusted EBITDA
We estimate that Adjusted EBITDA for the twelve months ending September 30, 2015 will be $66.8 million, compared to $35.5 million for the pro forma year ended December 31, 2013 and $24.4 million for the pro forma twelve months ended June 30, 2014. We use Adjusted EBITDA in our segment analysis because it is an important supplemental measure of our performance.
The anticipated increase in Adjusted EBITDA is primarily attributed to items previously discussed and is provided on a segment basis in the table below.
| |
Pro Forma | Forecasted | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in millions) |
Year Ended December 31, 2013 |
Twelve Months Ended June 30, 2014 |
Twelve Months Ending September 30, 2015 |
|||||||
Crude oil pipelines and storage |
$ | 14.7 | $ | 19.5 | $ | 36.0 | ||||
Crude oil supply and logistics |
14.7 | 7.9 | 17.6 | |||||||
Refined products terminals and storage |
16.1 | 12.4 | 13.3 | |||||||
NGL distribution and sales |
15.5 | 12.0 | 22.5 | |||||||
Discontinued operations(1) |
2.0 | 1.4 | — | |||||||
Public partnership general and administrative expenses(2) |
— | — | (3.5 | ) | ||||||
Corporate and other(3) |
(27.5 | ) | (28.8 | ) | (19.1 | ) | ||||
Total Adjusted EBITDA(4) |
$ | 35.5 | $ | 24.4 | $ | 66.8 | ||||
- (1)
- In
June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
- (2)
- Incremental
general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership are not included in our
Adjusted EBITDA for the pro forma periods but are included for the forecast period.
- (3)
- Includes general partnership expenses associated with managing all reportable segments, which includes the impact of professional fees of approximately $14.1 million and $12.7 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively. As previously discussed, we expect these professional fees to decrease by $12.5 million and $11.1 million for the twelve months ending September 30, 2015 compared to the pro forma
76
year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively.
- (4)
- Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."
Depreciation and Amortization
We estimate that depreciation and amortization expense for the twelve months ending September 30, 2015 will be $50.4 million, compared to $36.5 million for the pro forma year ended December 31, 2013 and $41.5 million for the pro forma twelve months ended June 30, 2014. Estimated depreciation and amortization expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation and amortization methodologies. The increase in depreciation and amortization expense is primarily attributable to our expected increase in maintenance capital expenditures and expansion capital expenditures during the twelve months ending September 30, 2015.
Capital Expenditures
We estimate that total non-acquisition related capital expenditures for the twelve months ending September 30, 2015 will be $112.7 million, compared to non-acquisition related capital expenditures of $47.7 million for the pro forma year ended December 31, 2013 and $35.5 million for the pro forma twelve months ended June 30, 2014.
Maintenance capital expenditures. We estimate that we will spend $4.0 million on maintenance capital expenditures for the twelve months ending September 30, 2015, compared to $3.5 million spent during the pro forma year ended December 31, 2013 and $2.4 million spent during the pro forma twelve months ended June 30, 2014. We believe our forecasted maintenance capital expenditures are consistent with historical spending. The types of maintenance capital expenditures that we expect to incur include vehicle replacement costs for our crude oil service fleet, repairs to our NGL customer service centers, replacement and tank maintenance for our cylinder exchange business and replacement of rack loading equipment at our refined products terminals. For a discussion of our maintenance capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."
Expansion capital expenditures. We estimate that we will spend $108.7 million on expansion capital expenditures for the twelve months ending September 30, 2015, compared to $44.2 million for the pro forma year ended December 31, 2013 and $33.1 million for the pro forma twelve months ended June 30, 2014. Of the expansion capital expenditures for the pro forma year ended December 31, 2013 and pro forma twelve months ended June 30, 2014, $22.0 million and $13.2 million, respectively related to expansion projects to our Silver Dollar Pipeline System. Our planned capital expenditures primarily relate to the following, all of which will be funded by borrowings under our revolving credit facility:
- •
- In March 2014, we amended a five-year agreement with an existing customer to significantly increase that customer's
minimum volume commitment and allowed us to commit to expand the Silver Dollar Pipeline System by adding 30 miles of additional pipeline, including an interconnection to a second long-haul
transportation pipeline. We expect to complete these projects in the fourth quarter of 2014 at a cost of approximately $15.9 million, $5.4 million of which will be incurred during the
twelve months ending September 30, 2015.
- •
- Based on ongoing discussions with producers and marketers in the Southern Wolfcamp, during the twelve months ending September 30, 2015, we expect to incur an additional $78.1 million of
77
- •
- The addition of new large-volume or national accounts in our cylinder exchange business, which is expected to cost
$9.3 million during the twelve months ending September 30, 2015 and is expected to be completed by the end of 2015.
- •
- The addition of diluent capabilities at our Caddo Mills refined products terminal, which is expected to cost
$4.0 million during the twelve months ending September 30, 2015 and is expected to be completed by the second quarter of 2015.
- •
- The addition of butane blending at our North Little Rock refined products terminal, which is expected to cost
$3.2 million during the twelve months ending September 30, 2015 and is expected to be completed by the fourth quarter of 2014.
- •
- The remaining $8.7 million of expansion capital expenditures relate primarily to various planned organic growth projects within our crude oil supply and NGL sales businesses.
expansion capital expenditures to (i) build additional laterals underpinned by acreage dedications or volume commitments, (ii) connect additional central production facilities, (iii) add storage capacity, (iv) build additional truck injection stations and (v) interconnect with an additional third-party long-haul crude oil transportation pipeline. The new interconnection will increase takeaway capacity of the Silver Dollar Pipeline System and further diversify the market access we offer our customers.
For a discussion of our expansion capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."
Financing
Cash and indebtedness. Upon the completion of this offering and after using the net proceeds from this offering to repay amounts outstanding under our revolving credit facility as described in "Use of Proceeds," we expect to have approximately $75.0 million of outstanding indebtedness under our revolving credit facility, with available capacity of approximately $200.0 million. Our revolving credit facility contains an accordion feature that will allow us to increase the borrowing capacity from $275.0 million to $425.0 million, subject to obtaining additional or increased lender commitments. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility."
We expect that our future sources of liquidity, including cash flow from operations and available borrowing capacity under our revolving credit facility, will be sufficient to fund capital expenditures included in this forecast. We intend to fund our forecasted expansion capital expenditures with borrowings under to our revolving credit facility.
Interest expense. Our average borrowings for the twelve months ending September 30, 2015 are expected to be approximately $152.8 million and bear interest at an estimated weighted-average rate of 2.88%. Accordingly, we expect to incur $6.4 million of interest expense during the twelve months ending September 30, 2015 related to $5.3 million of interest expense on our expected credit facility borrowings, unused commitment fees and letters of credit fees, $0.8 million of amortization of deferred financing costs and $0.3 million of interest on our other debt.
Regulatory, Industry, Economic and Other Factors
Our forecast for the twelve month period ending September 30, 2015, is based on the following significant assumptions related to regulatory, industry and economic factors:
- •
- there will not be any new federal, state or local regulation of any of the businesses we operate, or any new
interpretation of existing regulations, that will be materially adverse to our business;
- •
- there will not be any major adverse change in the midstream energy sector, any of the businesses we operate, commodity
prices, capital or insurance markets or general economic conditions;
- •
- there will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events
with respect to our facilities or those of third parties on which we depend;
- •
- we will not make any acquisitions or other significant expansion capital expenditures (other than as described above); and
- •
- market, insurance and overall economic conditions will not change substantially.
78
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
Distributions of Available Cash
General
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014 we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through December 31, 2014 based on the actual length of the period.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
- •
- less, the amount of cash reserves established by our general partner
to:
- •
- provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated
future debt service requirements);
- •
- comply with applicable law, any of our debt instruments or other agreements; or
- •
- provide funds for distributions to our unitholders and to our general partner for any one or more of the next four
quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum
quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
- •
- plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.
Intent to Distribute the Minimum Quarterly Distribution
Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.3250 per unit, or $1.30 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility" for a discussion of
79
the restrictions included in our revolving credit facility that may restrict our ability to make distributions.
General Partner Interest and Incentive Distribution Rights
Initially, our general partner will own a non-economic general partner interest. Our general partner holds incentive distribution rights that will entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.37375 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that our general partner or its affiliates may receive on common or subordinated units that they own. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.
Operating Surplus and Capital Surplus
General
All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.
Operating Surplus
We define operating surplus as:
- •
- $30.0 million (as described below); plus
- •
- all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined
below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly
installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus
- •
- working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus
for that quarter; plus
- •
- cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity
issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to
commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the
date that it is abandoned or disposed of; less
- •
- all of our operating expenditures (as defined below) after the closing of this offering; less
- •
- the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less
- •
- all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.
As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $30.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As
80
a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.
The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) capital contributions received by us.
We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized at the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:
- •
- repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as
described above);
- •
- payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working
capital borrowings;
- •
- expansion capital expenditures;
- •
- payment of transaction expenses (including taxes) relating to interim capital transactions;
- •
- distributions to our partners;
- •
- repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans);
or
- •
- any other expenditures or payments using the proceeds of this offering that are described in "Use of Proceeds."
Capital Surplus
Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:
- •
- borrowings other than working capital borrowings;
81
- •
- sales of our equity and debt securities;
- •
- sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary
course of business or as part of ordinary course retirement or replacement of assets; and
- •
- capital contributions received.
Characterization of Cash Distributions
All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $30.0 million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.
Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain our operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, for routine vehicle replacement costs for our crude oil service fleet and our NGL hard shell tank trucks, repairs to our NGL customer service centers, replacement and tank maintenance for our cylinder exchange business and replacement of rack loading equipment at our refined products terminals.
Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional crude oil storage facilities, crude oil pipelines, crude oil gathering and transportation trucks, refined products terminals, cylinder exchanges cages, NGL hard shell tank trucks and cylinders and related or similar midstream assets.
Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures do not. Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.
82
Subordinated Units and Subordination Period
General
Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3250 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.
Subordination Period
Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2017, that each of the following tests are met:
- •
- distributions of available cash from operating surplus on each of the outstanding common units and subordinated units
equaled or exceeded $1.30 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that
date;
- •
- the adjusted operating surplus (as defined below) generated during each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.30 (the annualized minimum quarterly distribution) on all of the
outstanding common units and subordinated units during those periods on a fully diluted basis; and
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
For the period after the closing of this offering through December 31, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.
Early Termination of the Subordination Period
Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2015, that each of the following tests are met:
- •
- distributions of available cash from operating surplus on each of the outstanding common units and subordinated units
equaled or exceeded $1.95 (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;
- •
- the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.95 (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and
83
- •
- there are no arrearages in payment of the minimum quarterly distributions on the common units.
Expiration Upon Removal of the General Partner
In addition, if the unitholders remove our general partner other than for cause:
- •
- the subordinated units held by any person will immediately and automatically convert into common units on a
one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an
affiliate of the successor general partner;
- •
- if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common
units will be extinguished and the subordination period will end; and
- •
- our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
Expiration of the Subordination Period
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.
Adjusted Operating Surplus
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:
- •
- operating surplus generated with respect to that period (excluding any amount attributable to the item described in the
first bullet of the definition of operating surplus); less
- •
- any net increase in working capital borrowings with respect to that period; less
- •
- any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating
expenditure made with respect to that period; plus
- •
- any net decrease in working capital borrowings with respect to that period; plus
- •
- any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect
to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus
- •
- any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
Distributions of Available Cash From Operating Surplus During the Subordination Period
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
- •
- first, 100.0% to the common unitholders, pro rata, until we distribute for
each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
- •
- second, 100.0% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
84
- •
- third, 100.0% to the subordinated unitholders, pro rata, until we
distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.
The preceding discussion is based on the assumption that we do not issue additional classes of equity securities.
Distributions of Available Cash From Operating Surplus After the Subordination Period
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
- •
- first, 100.0% to all unitholders, pro rata, until we distribute for each
outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.
The preceding discussion is based on the assumption that we do not issue additional classes of equity securities.
General Partner Interest and Incentive Distribution Rights
Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us, and will be entitled to receive distributions on such interests.
Incentive distribution rights represent the right to receive an increasing percentage (15.0%, 25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
The following discussion assumes that there are no arrearages on the common units and that our general partner continues to own the incentive distribution rights.
If for any quarter:
- •
- we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an
amount equal to the minimum quarterly distribution; and
- •
- we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
- •
- first, 100.0% to all unitholders, pro rata, until each unitholder receives
a total of $0.37375 per unit for that quarter (the "first target distribution");
- •
- second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.40625 per unit for that quarter (the "second target distribution");
85
- •
- third, 75.0% to all unitholders, pro rata, and 25.0% to our general
partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.4875 per unit for that quarter (the "third target distribution"); and
- •
- thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).
Percentage Allocations of Available Cash From Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) based on the specified target distribution levels. The amounts set forth under "Marginal percentage interest in distributions" are the percentage interests of our general partner (in its capacity as the holder of our incentive distribution rights) and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total quarterly distribution per unit target amount." The percentage interests shown for our unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner (in its capacity as the holder of our incentive distribution rights) assume that our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
| |
|
|
Marginal Percentage Interest in Distributions |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Total Quarterly Distribution Per Unit Target Amount |
Unitholders | General Partner (in Its Capacity as the Holder of Our Incentive Distribution Rights) |
||||||||
Minimum quarterly distribution |
$0.32500 | 100 | % | — | |||||||
First target distribution |
above $0.32500 | up to $0.37375 | 100 | % | — | ||||||
Second target distribution |
above $0.37375 | up to $0.40625 | 85 | % | 15 | % | |||||
Third target distribution |
above $0.40625 | up to $0.48750 | 75 | % | 25 | % | |||||
Thereafter |
above $0.48750 | 50 | % | 50 | % | ||||||
General Partner's Right to Reset Incentive Distribution Levels
Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is
86
made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.
In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period.
The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.
Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:
- •
- first, 100.0% to all unitholders, pro rata, until each unitholder receives
an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;
- •
- second, 85.0% to all unitholders, pro rata, and 15.0% to our general
partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the
quarter;
- •
- third, 75.0% to all unitholders, pro rata, and 25.0% to our general
partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the
quarter; and
- •
- thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the
87
assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.50.
| |
|
|
Marginal Percentage Interest in Distributions |
|
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Quarterly Distribution Per Unit Prior to Reset |
Common Unitholders |
General Partner (in Its Capacity as the Holder of Our Incentive Distribution Rights) |
Quarterly Distribution Per Unit Following Hypothetical Reset |
||||||||||
Minimum quarterly distribution |
$0.32500 | 100.0 | % | — | $0.5000 | |||||||||
First target distribution |
above $0.32500 | up to $0.37375 | 100.0 | % | — | above $0.5000 | up to $0.5750(1) | |||||||
Second target distribution |
above $0.37375 | up to $0.40625 | 85.0 | % | 15.0 | % | above $0.5750(1) | up to $0.6250(2) | ||||||
Third target distribution |
above $0.40625 | up to $0.48750 | 75.0 | % | 25.0 | % | above $0.6250(2) | up to $0.7500(3) | ||||||
Thereafter |
above $0.48750 | 50.0 | % | 50.0 | % | above $0.7500(3) | ||||||||
- (1)
- This
amount is 115.0% of the hypothetical reset minimum quarterly distribution.
- (2)
- This
amount is 125.0% of the hypothetical reset minimum quarterly distribution.
- (3)
- This amount is 150.0% of the hypothetical reset minimum quarterly distribution.
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights), based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 36,427,004 common units outstanding, and the average distribution to each common unit would be $0.5000 per quarter for the two consecutive non-overlapping quarters prior to the reset.
| |
Quarterly Distribution Per Unit Prior to Reset |
Cash Distributions to Common Unitholders Prior to Reset |
Cash Distribution to General Partner (in its Capacity as the Holder of Our Incentive Distribution Rights) Prior to Reset |
Total Distributions | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Minimum quarterly distribution |
$0.32500 | $ | 11,838,776 | $ | — | $ | 11,838,776 | |||||||
First target distribution |
above $0.32500 | up to $0.37375 | 1,775,816 | — | 1,775,816 | |||||||||
Second target distribution |
above $0.37375 | up to $0.40625 | 1,183,878 | 208,920 | 1,392,797 | |||||||||
Third target distribution |
above $0.40625 | up to $0.48750 | 2,959,694 | 986,565 | 3,946,259 | |||||||||
Thereafter |
above $0.48750 | 455,338 | 455,338 | 910,675 | ||||||||||
|
$ | 18,213,502 | $ | 1,650,822 | $ | 19,864,324 | ||||||||
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner (in its capacity as the holder of our incentive distribution rights), with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be 39,728,648 common units outstanding and that the average distribution to each common unit would be $0.50. The number of common units issued as a result of the reset was calculated by dividing (x) 1,650,822 as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common
88
unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $0.50000.
| |
|
|
|
Cash Distribution to General Partner After Reset |
|
|||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
Cash Distributions to Common Unitholders After Reset |
|
||||||||||||||||
| |
Quarterly Distribution Per Unit After Reset |
Common Units |
Incentive Distribution Rights |
Total | Total Distributions |
|||||||||||||||
Minimum quarterly distribution |
$0.50000 | $ | 18,213,502 | $ | 1,650,822 | $ | — | $ | 1,650,822 | $ | 19,864,324 | |||||||||
First target distribution |
above $0.50000 | up to $0.57500 | — | — | — | |||||||||||||||
Second target distribution |
above $0.57500 | up to $0.62500 | — | — | — | |||||||||||||||
Third target distribution |
above $0.62500 | up to $0.75000 | — | — | — | |||||||||||||||
Thereafter |
above $0.75000 | — | — | — | ||||||||||||||||
|
$ | 18,213,502 | $ | 1,650,822 | $ | — | $ | 1,650,822 | $ | 19,864,324 | ||||||||||
Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.
Distributions From Capital Surplus
How Distributions From Capital Surplus Will Be Made
We will make distributions of available cash from capital surplus, if any, in the following manner:
- •
- first, 100.0% to all unitholders, pro rata, until we distribute for each
common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;
- •
- second, 100.0% to all unitholders, pro rata, until we distribute for each
common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and
- •
- thereafter, as if they were from operating surplus.
The preceding discussion is based on the assumption we do not issue additional classes of equity securities.
Effect of a Distribution From Capital Surplus
Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to the holder of our incentive distribution rights.
89
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:
- •
- the minimum quarterly distribution;
- •
- target distribution levels;
- •
- the unrecovered initial unit price; and
- •
- the arrearages in payment of the minimum quarterly distribution on the common units.
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.
In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.
Distributions of Cash Upon Liquidation
General
If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be distributable cash flow available to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.
90
Manner of Adjustments for Gain
The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:
- •
- first, 100.0% to the common unitholders, pro rata, until the capital
account for each common unit is equal to the sum of:
- (1)
- the
unrecovered initial unit price;
- (2)
- the
amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and
- (3)
- any
unpaid arrearages in payment of the minimum quarterly distribution;
- •
- second, 100.0% to the subordinated unitholders, pro rata, until the
capital account for each subordinated unit is equal to the sum of:
- (1)
- the
unrecovered initial unit price; and
- (2)
- the
amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
- •
- third, 100.0% to all unitholders, pro rata, until we allocate under this
paragraph an amount per unit equal to:
- (1)
- the
sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less
- (2)
- the
cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that
we distributed 100.0% to the unitholders, pro rata, for each quarter of our existence;
- •
- fourth, 85.0% to all unitholders, pro rata, and 15.0% to our general
partner (in its capacity as the holder of our incentive distribution rights), until we allocate under this paragraph an amount per unit equal to:
- (1)
- the
sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less
- (2)
- the
cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we
distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights) for each quarter of our existence;
- •
- fifth, 75.0% to all unitholders, pro rata, and 25.0% to our general
partner (in its capacity as the holder of our incentive distribution rights), until we allocate under this paragraph an amount per unit equal to:
- (1)
- the
sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less
- (2)
- the
cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we
distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights) for each quarter of our existence;
- •
- thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).
91
The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.
Manner of Adjustments for Losses
If our liquidation occurs before the end of the subordination period, after making allocations of loss to the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our unitholders in the following manner:
- •
- first, 100.0% to the holders of subordinated units in proportion to the
positive balances in their capital accounts, until the capital accounts of the subordinated unitholders have been reduced to zero; and
- •
- thereafter, 100.0% to the holders of common units in accordance with their percentage interest in us.
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
Adjustments to Capital Accounts
We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we generally will allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders based on their percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.
92
SELECTED HISTORICAL AND PRO FORMA COMBINED CONSOLIDATED FINANCIAL AND OPERATING DATA
The table set forth below presents, as of the dates and for the periods indicated, our selected historical and pro forma combined consolidated financial and operating data.
The selected historical consolidated financial data presented as of December 31, 2012 and December 31, 2013 and for the years ended December 31, 2011, December 31, 2012 and December 31, 2013 have been derived from our audited historical consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2013 and June 30, 2014 and for the six months ended June 30, 2013 and June 30, 2014 are derived from our unaudited historical condensed consolidated financial statements.
The summary pro forma combined consolidated statement of operations for the six months ended June 30, 2014 includes the pro forma effects of the recapitalization transactions, including this offering, described under "—Recapitalization Transactions and Partnership Structure" as if the recapitalization transactions, including this offering, occurred on January 1, 2013. The selected historical consolidated financial data presented as of December 31, 2010 and for the period for May 5, 2010 (date of inception) to December 31, 2010 is derived from our unaudited historical consolidated financial statements that are not included in this prospectus.
The selected pro forma combined consolidated balance sheet as of June 30, 2014 was prepared as if the recapitalization transactions occurred on June 30, 2014. The selected pro forma combined consolidated statement of operations for the year ended December 31, 2013 gives effect to (i) our acquisition of the Silver Dollar Pipeline System as if it had occurred on January 1, 2013 and (ii) the recapitalization transactions, including this offering, as if they had occurred on January 1, 2013.
During 2013, we determined that our previously issued audited consolidated financial statements as of December 31, 2012 and results of operations for the year ended December 31, 2012 contained errors. We evaluated those errors and determined that the impact of these errors was material to the results of operations for the year ended December 31, 2012. Accordingly, our previously audited consolidated balance sheet at December 31, 2012 and the statement of operations and statement of cash flows for the year ended December 31, 2012 have been restated to reflect the correction of the errors, including the correction of immaterial errors. Please read note 3 of our consolidated financial statements included elsewhere in this prospectus.
On February 12, 2014, we acquired certain assets from JP Development. Because we and JP Development are both affiliates of ArcLight, this was a transaction between commonly controlled entities and we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the acquired assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the acquired assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the acquired assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."
For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with our unaudited pro forma combined consolidated financial statements and audited and unaudited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma combined consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.
93
The following table presents Adjusted EBITDA, distributable cash flow and adjusted gross margin, financial measures that are not presented in accordance with GAAP. For a discussion of how we derive these measures and a reconciliation of Adjusted EBITDA, distributable cash flow and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP, please read "—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."
| |
|
|
|
|
|
|
Pro Forma | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Unaudited Period from May 5, 2010 (date of inception) to December 31, 2010 |
Year Ended December 31, |
Six Months Ended June 30, |
||||||||||||||||||||||
| |
|
Six Months Ended June 30, 2014 |
|||||||||||||||||||||||
| |
Year Ended December 31, 2013 |
||||||||||||||||||||||||
| ($ in thousands, except per unit amounts) |
2011 | 2012(1) | 2013(1) | 2013 | 2014 | ||||||||||||||||||||
| |
|
|
(Restated and recast) |
|
(unaudited) |
(unaudited) |
|||||||||||||||||||
Statement of Operations Data: |
|||||||||||||||||||||||||
Total revenue |
$ | 8,541 | $ | 67,156 | $ | 427,581 | $ | 2,102,233 | $ | 987,804 | $ | 865,817 | $ | 2,105,201 | $ | 865,817 | |||||||||
Costs and expenses: |
|||||||||||||||||||||||||
Cost of sales, excluding depreciation and amortization |
6,853 | 49,048 | 368,791 | 1,964,631 | 918,957 | 798,193 | 1,964,631 | 798,193 | |||||||||||||||||
Operating expenses |
1,656 | 9,584 | 28,640 | 61,925 | 28,202 | 35,266 | 62,996 | 35,266 | |||||||||||||||||
General and administrative |
2,163 | 6,053 | 20,983 | 45,284 | 20,313 | 23,879 | 45,699 | (2) | 23,838 | (2) | |||||||||||||||
Depreciation and amortization |
437 | 2,841 | 13,856 | 33,345 | 15,186 | 20,165 | 36,524 | 20,165 | |||||||||||||||||
Loss on disposal of assets |
— | 68 | 1,142 | 1,492 | 998 | 661 | 1,492 | 661 | |||||||||||||||||
Operating income (loss) |
(2,568 | ) | (438 | ) | (5,831 | ) | (4,444 | ) | 4,148 | (12,347 | ) | (6,141 | ) | (12,306 | ) | ||||||||||
Other income (expense): |
|||||||||||||||||||||||||
Interest (expense) |
(57 | ) | (633 | ) | (3,405 | ) | (9,075 | ) | (3,815 | ) | (5,551 | ) | (4,714 | ) | (2,308 | ) | |||||||||
Loss on extinguishment of debt |
— | (95 | ) | (497 | ) | — | — | 1,634 | — | — | |||||||||||||||
Other income, net |
— | — | 247 | 688 | 195 | 504 | 688 | 504 | |||||||||||||||||
Income (loss) before income taxes |
(2,625 | ) | (1,166 | ) | (9,486 | ) | (12,831 | ) | 528 | (19,208 | ) | (10,167 | ) | (14,110 | ) | ||||||||||
Income tax (expense) benefit |
— | (35 | ) | (222 | ) | (208 | ) | (305 | ) | (156 | ) | (227 | ) | (156 | ) | ||||||||||
Net income (loss) from continuing operations |
(2,625 | ) | (1,201 | ) | (9,708 | ) | (13,039 | ) | 223 | (19,184 | ) | (10,394 | ) | (14,266 | ) | ||||||||||
Net income (loss) from discontinued operations(3) |
— | — | 1,320 | (1,182 | ) | (23 | ) | (9,608 | ) | — | — | ||||||||||||||
Net income (loss) |
(2,625 | ) | (1,201 | ) | (8,388 | ) | (14,221 | ) | $ | 200 | $ | (28,792 | ) | $ | (10,394 | ) | $ | (14,266 | ) | ||||||
General partner's interest in pro forma net income (loss) |
|||||||||||||||||||||||||
Common unit holder's interest in pro forma net income (loss) |
(5,197 | ) | (7,133 | ) | |||||||||||||||||||||
Subordinated unit holder's interest in pro forma net income (loss) |
(5,197 | ) | (7,133 | ) | |||||||||||||||||||||
Pro forma net income per common unit |
(0.29 | ) | (0.39 | ) | |||||||||||||||||||||
Pro forma net income per subordinated unit |
(0.29 | ) | (0.39 | ) | |||||||||||||||||||||
Weighted average number of limited partner units outstanding |
|||||||||||||||||||||||||
Common units |
18,213,502 | 18,213,502 | |||||||||||||||||||||||
Subordinated units |
18,213,502 | 18,213,502 | |||||||||||||||||||||||
Statement of Cash Flows Data: |
|||||||||||||||||||||||||
Cash provided by (used in): |
|||||||||||||||||||||||||
Operating activities |
$ | (2,796 | ) | $ | (5,895 | ) | $ | (6,990 | ) | $ | 13,882 | $ | 24,778 | $ | 7,572 | ||||||||||
Investing activities(4) |
(21,911 | ) | (26,860 | ) | (292,334 | ) | (27,735 | ) | (13,986 | ) | (4,936 | ) | |||||||||||||
Financing activities(5) |
27,068 | 34,825 | 304,991 | (4) | 6,988 | (11,482 | ) | (4,744 | ) | ||||||||||||||||
Other Financial Data(6): |
|||||||||||||||||||||||||
Adjusted gross margin |
1,688 | 18,108 | 57,203 | 136,491 | $ | 68,938 | $ | 68,553 | $ | 139,459 | $ | 68,553 | |||||||||||||
Adjusted EBITDA |
$ | (2,123 | ) | $ | 2,825 | $ | 14,560 | $ | 34,284 | 23,855 | 12,038 | 35,527 | 12,035 | ||||||||||||
Distributable cash flow |
(2,225 | ) | 1,902 | 11,341 | 23,755 | 18,710 | 6,286 | 24,288 | 7,044 | ||||||||||||||||
Balance Sheet Data: |
|||||||||||||||||||||||||
Cash and cash equivalents |
$ | 2,362 | $ | 4,432 | $ | 10,099 | $ | 3,234 | $ | 9,409 | $ | 1,126 | $ | 108,451 | |||||||||||
Accounts receivable, net |
3,789 | 12,246 | 80,551 | 122,919 | 79,038 | 158,265 | 50,940 | ||||||||||||||||||
Property, plant and equipment, net |
12,694 | 27,720 | 191,864 | 238,093 | 194,201 | 232,690 | 232,690 | ||||||||||||||||||
Total assets |
32,138 | 65,931 | 562,124 | 843,402 | 556,910 | 842,472 | 839,713 | ||||||||||||||||||
Total long-term debt (including current maturities) |
11,381 | 16,948 | 167,739 | 184,846 | 165,901 | 183,322 | 76,722 | ||||||||||||||||||
Total partners' capital |
10,216 | 41,466 | 314,153 | 533,393 | 308,808 | 505,506 | 609,601 | ||||||||||||||||||
Operating Data(7): |
|||||||||||||||||||||||||
Crude oil pipeline throughput (Bbl/d) |
— | — | — | 13,738 | (7) | — | 19,652 | 8,885 | (8) | 19,652 | |||||||||||||||
Crude oil sales (Bbl/d) |
— | — | 24,201 | 53,471 | 51,372 | 42,411 | 53,471 | 42,411 | |||||||||||||||||
Refined products terminals throughput (Mgal/d) |
— | — | 2,400 | 2,901 | 2,834 | 2,699 | 2,901 | 2,699 | |||||||||||||||||
NGL and refined product sales (Gal/d) |
15,028 | 61,314 | 128,775 | 180,850 | 182,463 | 199,016 | 180,850 | 199,016 | |||||||||||||||||
- (1)
- Our historical combined consolidated financial and operating data for the years ended December 31, 2012 and 2013 have been retrospectively adjusted for the JP Development Dropdown. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."
94
- (2)
- Includes
the impact of professional fees of approximately $14.1 million and $5.8 million for the pro forma combined year ended
December 31, 2013 and the pro forma combined six months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur in future periods. Excludes estimated
annual incremental cash expense associated with being a publicly traded partnership of approximately $3.5 million, including costs associated with SEC reporting requirements, tax return and
Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees,
incremental officer and director liability expenses and director compensation.
- (3)
- In
June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
- (4)
- Cash
used in investing activities includes the cash consideration paid for third party acquisitions during the period from May 5, 2010 to
December 31, 2010 and the years ended December 31, 2011, 2012 and 2013, as described in greater detail in "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
- (5)
- Cash
provided by financing activities for the year ended December 31, 2012 includes the issuance of units and borrowings under our 2011 revolving
credit facility to finance the purchase of certain third party acquisitions during the year ended December 31, 2012, as described in greater detail in "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
- (6)
- Adjusted
gross margin, Adjusted EBITDA and distributable cash flow are financial measures that are not presented in accordance with GAAP. Please read
"—Non-GAAP Financial Measures."
- (7)
- Represents
the average daily throughput volume in our crude oil pipelines and storage segment, the average daily sales volume in our crude oil supply and
logistics segment, the average daily throughput volume in our refined products terminals and storage segment and the average daily sales volume in our NGL distribution and sales segment.
- (8)
- The Silver Dollar Pipeline System was placed into service in April 2013 and acquired by us in October 2013. Average throughput for the year ended December 31, 2013 represents throughput from the date of acquisition through year end, while average throughput for the pro forma year ended December 31, 2013 represents throughput from the date the Silver Dollar Pipeline System was placed into service through year end.
Adjusted EBITDA and distributable cash flow. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation and non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA less net cash interest paid, income taxes paid and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances.
Adjusted gross margin. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivatives contracts (total gain (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).
Adjusted EBITDA, distributable cash flow and adjusted gross margin are supplemental non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
- •
- our operating performance as compared to those of other companies in the midstream sector, without regard to financing
methods, historical cost basis or capital structure;
- •
- the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
- •
- our ability to incur and service debt and fund capital expenditures; and
- •
- the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Adjusted EBITDA, distributable cash flow and adjusted gross margin are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP measures in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and cash flow provided by operating activities, respectively, and the GAAP measure most directly comparable to adjusted gross margin is operating income (loss). Adjusted
95
EBITDA, distributable cash flow and adjusted gross margin should not be considered an alternative to net income, cash flow provided by operating activities, operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA, distributable cash flow and adjusted gross margin exclude some, but not all, items that affect net income and cash flow provided by operating activities, and these measures may vary among other companies. As a result, Adjusted EBITDA, distributable cash flow and adjusted gross margin may not be comparable to similarly titled measures of other companies.
The following tables reconcile (i) Adjusted EBITDA (which consists of the sum of Adjusted EBITDA for each of our business segments less general and administrative expenses associated with managing all reportable segments that are not specifically attributed to any segments) and distributable cash flow to net income and to cash provided by (used in) operating activities, respectively, their most directly comparable GAAP financial measures, and (ii) adjusted gross margin to operating income (loss), its most directly comparable GAAP financial measure, on a historical and pro forma basis, as applicable, for each of the periods indicated.
| |
|
|
|
|
|
|
Pro Forma | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Unaudited Period from May 5, 2010 (date of inception) to December 31, 2010 |
|
|
|
Six Months Ended June 30, | ||||||||||||||||||||
| |
Year Ended December 31, | |
Six Months Ended June 30, 2014 |
||||||||||||||||||||||
| |
Year Ended December 31, 2013 |
||||||||||||||||||||||||
| |
2011 | 2012 | 2013 | 2013 | 2014 | ||||||||||||||||||||
| ($ in thousands) |
|
|
(Restated and recast) |
|
|
|
|
|
|||||||||||||||||
Reconciliation of Adjusted EBITDA and distributable cash flow to net income (loss) and to cash flow provided by (used in) operating activities |
|||||||||||||||||||||||||
Net cash provided by (used in) operating activities |
$ | (2,796 | ) | $ | (5,895 | ) | $ | (6,990 | ) | $ | 13,882 | $ | 24,778 | $ | 7,572 | ||||||||||
Depreciation and amortization |
(437 | ) | (2,841 | ) | (15,126 | ) | (36,195 | ) | (16,603 | ) | (21,599 | ) | |||||||||||||
Goodwill impairment |
— | — | — | — | — | (1,984 | ) | ||||||||||||||||||
Unit-based compensation |
— | — | (2,485 | ) | (948 | ) | (371 | ) | (584 | ) | |||||||||||||||
Amortization of deferred financing costs |
— | (30 | ) | (490 | ) | (1,103 | ) | (562 | ) | (459 | ) | ||||||||||||||
Derivative valuation changes |
— | — | 1,330 | 1,162 | 90 | (617 | ) | ||||||||||||||||||
Loss on disposal of assets |
— | (68 | ) | (1,142 | ) | (1,492 | ) | (998 | ) | (7,709 | ) | ||||||||||||||
Provision for bad debt expense |
— | (160 | ) | (826 | ) | (855 | ) | (331 | ) | (555 | ) | ||||||||||||||
Loss on extinguishment of debt |
— | (95 | ) | (497 | ) | — | — | (1,634 | ) | ||||||||||||||||
Other non-cash items |
— | (69 | ) | (131 | ) | 378 | (56 | ) | 74 | ||||||||||||||||
Changes in assets and liabilities |
608 | 7,957 | 17,969 | 10,950 | (5,747 | ) | (1,297 | ) | |||||||||||||||||
Net income (loss) |
(2,625 | ) | (1,201 | ) | (8,388 | ) | (14,221 | ) | $ | 200 | $ | (28,792 | ) | $ | (10,394) | (1) | $ | (14,266) | (1) | ||||||
Interest expense |
57 | 633 | 3,405 | 9,075 | 3,815 | 5,551 | 4,714 | 2,308 | |||||||||||||||||
Income taxes |
— | 35 | 222 | 208 | 305 | 156 | 227 | 156 | |||||||||||||||||
Depreciation and amortization(2) |
437 | 2,841 | 13,856 | 33,345 | 15,186 | 20,165 | 36,524 | 20,165 | |||||||||||||||||
Discontinued operations |
— | — | 1,435 | 3,205 | 1,600 | 10,591 | 2,023 | 983 | |||||||||||||||||
Loss on disposal of assets |
— | 68 | 1,142 | 1,492 | 998 | 661 | 1,492 | 661 | |||||||||||||||||
Total (gain) loss from commodity derivative contracts |
— | — | (640 | ) | (902 | ) | 610 | (32 | ) | (902 | ) | (32 | ) | ||||||||||||
Net cash receipts (payments) for commodity derivatives settled during the period |
— | — | (946 | ) | (209 | ) | (518 | ) | 588 | (209 | ) | 588 | |||||||||||||
Unit-based compensation |
— | — | 2,485 | 948 | 371 | 584 | 948 | 584 | |||||||||||||||||
Loss on extinguishment of debt |
— | 95 | 497 | — | — | 1,634 | — | — | |||||||||||||||||
Transaction costs and other non-cash items |
8 | 354 | 1,492 | 1,343 | 1,288 | 932 | 1,104 | 888 | |||||||||||||||||
Adjusted EBITDA |
(2,123 | ) | 2,825 | 14,560 | 34,284 | 23,855 | 12,038 | 35,527 | 12,035 | ||||||||||||||||
Less: |
|||||||||||||||||||||||||
Incremental general and administrative expenses of being a publicly traded partnership |
— | — | — | — | — | — | 3,525 | 1,763 | |||||||||||||||||
Cash interest paid, net of interest income |
41 | 646 | 1,757 | 7,063 | 2,732 | 4,372 | 4,126 | 1,849 | |||||||||||||||||
Cash income tax paid |
— | — | 35 | 106 | 75 | 200 | 106 | 200 | |||||||||||||||||
Expansion capital expenditures |
21,885 | 27,481 | 291,833 | 24,471 | 11,740 | 13,628 | 277,459 | 13,629 | |||||||||||||||||
Maintenance capital expenditures |
61 | 277 | 1,427 | 3,360 | 2,338 | 1,180 | 3,482 | 1,179 | |||||||||||||||||
Add: |
|||||||||||||||||||||||||
Capital contributions and borrowings to fund expansion capital expenditures |
21,885 | 27,481 | 291,833 | 24,471 | 11,740 | 13,628 | 277,459 | 13,629 | |||||||||||||||||
Distributable cash flow |
$ | (2,225 | ) | $ | 1,902 | $ | 11,341 | $ | 23,755 | $ | 18,710 | $ | 6,286 | $ | 24,288 | $ | 7,044 | ||||||||
- (1)
- Includes
the impact of professional fees of approximately $14.1 million and $5.8 million for the pro forma combined year ended
December 31, 2013 and the pro forma combined six months ended June 30, 2014.
- (2)
- In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
96
| |
Unaudited Period from May 5, 2010 (date of inception) to December 31, 2010 |
|
|
|
Six Months Ended June 30, |
Pro Forma | |||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Year Ended December 31, | ||||||||||||||||||||||||
| |
Year Ended December 31, 2013 |
Six Months Ended June 30, 2014 |
|||||||||||||||||||||||
| |
2011 | 2012 | 2013 | 2013 | 2014 | ||||||||||||||||||||
| ($ in thousands) |
|
|
|
|
|
|
|
|
|||||||||||||||||
Reconciliation of adjusted gross margin to operating income |
|||||||||||||||||||||||||
Adjusted gross margin |
|||||||||||||||||||||||||
Crude oil pipelines and storage |
$ | — | $ | — | $ | 6,000 | $ | 16,507 | $ | 7,200 | $ | 12,367 | $ | 19,475 | $ | 12,367 | |||||||||
Crude oil supply and logistics |
— | — | 3,342 | 26,280 | 13,238 | 6,474 | 26,280 | 6,474 | |||||||||||||||||
Refined products terminals and storage |
— | — | 1,732 | 19,327 | 10,250 | 9,806 | 19,327 | 9,806 | |||||||||||||||||
NGL distribution and sales |
1,688 | 18,108 | 46,129 | 74,377 | 38,250 | 39,906 | 74,377 | 39,906 | |||||||||||||||||
Corporate and other |
— | — | — | — | — | — | — | — | |||||||||||||||||
Total Adjusted gross margin |
1,688 | 18,108 | 57,203 | 136,491 | 68,938 | 68,553 | 139,459 | 68,553 | |||||||||||||||||
Operating expenses |
(1,656 | ) | (9,584 | ) | (28,640 | ) | (61,925 | ) | (28,202 | ) | (35,266 | ) | (62,996 | ) | (35,266 | ) | |||||||||
General and administrative |
(2,163 | ) | (6,053 | ) | (20,983 | ) | (45,284 | ) | (20,313 | ) | (23,879 | ) | (45,699 | ) | (23,838 | ) | |||||||||
Depreciation and amortization |
(437 | ) | (2,841 | ) | (13,856 | ) | (33,345 | ) | (15,186 | ) | (20,165 | ) | (36,524 | ) | (20,165 | ) | |||||||||
Loss on disposal of assets |
— | (68 | ) | (1,142 | ) | (1,492 | ) | (998 | ) | (661 | ) | (1,492 | ) | (661 | ) | ||||||||||
Total (gain) loss from commodity derivative contracts |
— | — | 640 | 902 | (610 | ) | 32 | 902 | 32 | ||||||||||||||||
Net cash receipts (payments) for commodity derivatives settled during the period |
— | — | 947 | 209 | 519 | (588 | ) | 209 | (588 | ) | |||||||||||||||
Other non-cash items |
— | — | — | — | — | (373 | ) | — | (373 | ) | |||||||||||||||
Operating income (loss) |
$ | (2,568 | ) | $ | (438 | ) | $ | (5,831 | ) | $ | (4,444 | ) | $ | 4,148 | $ | (12,347 | ) | $ | (6,141 | ) | $ | (12,306 | ) | ||
97
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the historical consolidated financial statements and notes of JP Energy Partners LP included elsewhere in this prospectus. Among other things, those historical consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled "Risk Factors" included elsewhere in this prospectus.
We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized in June 2011 by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of four business segments: (i) crude oil pipelines and storage, (ii) crude oil supply and logistics, (iii) refined products terminals and storage and (iv) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:
- •
- owning, operating and developing midstream assets serving areas experiencing dramatic increases in drilling activity and
production growth, as well as serving key crude oil, refined product and NGL distribution hubs;
- •
- providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing
product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and
- •
- operating one of the largest propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.
We intend to continue to expand our business by acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs.
JP Development Acquisition and Recast of Historical Financial Statements
On February 12, 2014, we acquired from JP Development an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets (collectively, the "Dropdown Assets") for approximately $319.1 million, inclusive of a working capital adjustment (the "JP Development Dropdown"). The consideration consisted of 12,561,934 of our Class A common units and $52.0 million in cash. The cash portion of the acquisition was funded from borrowings under our credit agreement with Bank of America, N.A. as administrative agent. The acquisition expanded our presence in the Permian Basin, one of the most prolific, high-growth, oil and liquids-rich basins in the United States.
Because the JP Development Dropdown was a transaction between commonly controlled entities (i.e. the buyer and sellers are each affiliates of ArcLight), we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the Dropdown Assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).
98
We refer herein to acquisitions made by JP Development of the assets that were subsequently acquired by us through the JP Development Dropdown as our acquisitions because we include the operating results for those assets in our financial statements from the date JP Development acquired them. However, we do not include capital expenditures made by JP Development to acquire assets subsequently acquired by us in the discussion of our capital expenditures.
Revolving Credit Facility
On February 12, 2014, we entered into a revolving credit facility with Bank of America, N.A., as administrative agent, and a syndicate of lenders (the "revolving credit facility") for working capital requirements, for the acquisition of entities, and to pay off our credit agreement with Wells Fargo Bank, N.A. (the "2011 revolving credit facility") and the term loans under our credit agreement with F&M Bank & Trust Company (the "F&M Bank credit agreement"). Our revolving credit facility consists of a $275 million revolving line of credit, which includes a sub-limit of up to $100 million for letters of credit, and matures on February 12, 2019. For more information about our revolving credit facility and other financing arrangements, please read "—Liquidity and Capital Resources."
Issuance of Series D Convertible Preferred Units
On March 28, 2014, we issued 1,818,182 Series D Convertible Preferred Units (the "Series D Preferred Units") to Lonestar for a cash purchase price of $22.00 per Series D Preferred Unit pursuant to the terms of an agreement by and among us, our general partner and Lonestar. This transaction resulted in proceeds to us of $40.0 million.
Disposition of Assets
On June 30, 2014, we entered into and simultaneously closed an Asset Purchase Agreement (the "Purchase Agreement") with Gold Spur Trucking, LLC ("Buyer") pursuant to which the we sold all of our trucking and related assets and activities in North Dakota, Montana and Wyoming (the "Bakken Business") to the Buyer for a purchase price of $9.1 million. As a result, we recognized a loss on this sale of approximately $9.3 million during the second quarter of 2014, which primarily relates to the write-off of a customer contract and goodwill associated with the Bakken Business.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements for consistency and trend analysis. These metrics include volumes, revenues, cost of sales, excluding depreciation and amortization, operating expenses, Adjusted EBITDA and distributable cash flow. Although we have not quantified distributable cash flow historically, we intend to use distributable cash flow to assess our performance after the closing of this offering.
- •
- Volumes and revenues.
- •
- Crude oil pipelines and storage. The amount of revenue we
generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a substantial majority of our crude oil pipeline revenues through long-term contracts containing
acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The volume of crude
oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell
capacity that is not contingent on the usage of our storage tanks.
- •
- Crude oil supply and logistics. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil
99
- •
- Refined products terminals and storage. The amount of
revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined
products in the markets served directly or indirectly by our refined products terminals, which we believe are strategically located to take advantage of infrastructure development opportunities
resulting from shifting flows of refined product fuels from the Mid-Continent to the Gulf Coast.
- •
- NGL distribution and sales. The amount of revenue we
generate from our NGL distribution and sales segment depends on the gallons of NGLs we sell through our cylinder exchange and NGL sales businesses. In addition, our NGL transportation operations
generate revenue based on the number of gallons of NGLs we gather and the distance we transport those gallons for our customers.
- •
- Cost of sales, excluding depreciation and
amortization. Our management attempts to minimize cost of sales, excluding depreciation and amortization, in order to enhance the
profitability of our operations. Cost of sales, excluding depreciation and amortization, includes the costs to purchase the product and any costs incurred to transport the product to the point of sale
and to store the product until it is sold. We seek to minimize cost of sales, excluding depreciation and amortization, by attempting to acquire the products which we use in each of our segments at
times and prices which are most optimal based on our knowledge of the industry and the regions in which we operate.
- •
- Operating expenses. Our management seeks to maximize the
profitability of our operations in part by minimizing operating expenses. These expenses are comprised of payroll, wages and benefits, utility costs, fleet costs, repair and maintenance costs, rent,
fuel, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle. We seek to manage our maintenance capital expenditures by scheduling maintenance over
time to avoid significant variability in our maintenance capital expenditures and minimize their impact on our cash flow.
- •
- Adjusted EBITDA and distributable cash flow. Our management uses Adjusted EBITDA and distributable cash flow to analyze our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define distributable cash flow as Adjusted EBITDA less net cash interest paid, income taxes paid and maintenance capital expenditures. Distributable cash flow will not reflect changes in working capital balances.
that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers.
Adjusted EBITDA and distributable cash flow are supplemental, non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
- •
- our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;
Adjusted EBITDA
100
- •
- the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
- •
- our ability to incur and service debt and fund capital expenditures; and
- •
- the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
- •
- the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
and
- •
- the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Distributable cash flow
Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and cash flow provided by operating activities. Adjusted EBITDA and distributable cash flow should not be considered as an alternative to net income, cash flow provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow exclude some, but not all, items that affect net income and cash flow provided by operating activities and these measures may vary among other companies. As a result, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies. For a reconciliation of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measure calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."
Our business is subject to the key trends discussed below. We have based our expectations on assumptions made by us and on the basis of information currently available to us. To the extent our underlying assumptions about our interpretation of available information prove to be incorrect, our actual results may vary from our expected results. Please read "Risk Factors" for additional information about the risks associated with purchasing our common units.
Production
Over the past several years, there has been a fundamental shift in crude oil production in the United States towards unconventional resources. According to the EIA, this includes crude oil produced from shale formations, tight gas and coal beds. The emergence of unconventional crude oil plays, such as in the Permian Basin, and advances in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of crude oil from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale production. The development of these unconventional sources has offset declines in other, more traditional hydrocarbon supply sources, which has helped meet growing demand and lowered the need for imported crude oil.
Production of Refined Products
Access to lower cost crude oil supplies has enabled inland refineries to produce refined petroleum products at a cost that allows them to compete over a much broader geographic area with supply from refineries located on the Gulf Coast. This dynamic has significantly diminished the flow of crude oil from the Gulf Coast to the Midwest and increased the flow of refined petroleum products from the Midwest to the Gulf Coast. We believe the changing dynamics of crude oil production may offer
101
opportunities to grow the throughput and value of our refined products terminals by completing projects to connect them to additional, less-expensive sources of product supply.
In the third quarter of 2014, we discovered that our product measurement and quality control processes at our refined products terminal in North Little Rock, Arkansas were resulting in excessive product gains for JP Energy. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. We have recorded a charge of $2.7 million as of June 30, 2014, which represents management's estimate of the value of refined products we will return to our customers.
We believe it is reasonably likely that the new processes and procedures that we are undertaking will result in a decrease in revenues from product sales in our refined products terminals and storage segment in future periods relative to historical periods, although this reduction may be partially offset by an operational excellence initiative that we are undertaking at both of our refined products terminals. For more information, please read "Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2015—Revenues, Cost of Sales and Adjusted Gross Margin—Refined Products Terminals and Storage."
Supply of Crude Oil Storage Capacity
An important factor in determining the value of our crude oil storage capacity and the rates we are able to charge for new contracts or contract renewals is whether a surplus or shortfall of crude oil storage capacity exists relative to the overall demand for crude oil storage services in a given market area. We currently have a long-term contract with the user of our crude oil storage capacity in Cushing, Oklahoma that has a remaining term of approximately 3.0 years as of June 30, 2014. We believe the demand for crude oil storage capacity in our market area will remain strong because of rising inland United States and Canadian production and the integral role that the Cushing interchange plays in facilitating the transfer of crude oil to refiners on the Gulf Coast.
Seasonality
The financial and operational results in our NGL distribution and sales segment are impacted by the seasonal nature of propane demand. The retail propane business is seasonal because of increased demand during the months of November through March primarily for the purpose of providing heating in residential and commercial buildings. As a result, the volume of propane we sell is at its highest during our first and fourth quarters and is directly affected by the severity of the winter. However, our cylinder exchange business sales volumes provide us increased operating profits during our second and third quarters, which reduces overall seasonal fluctuations in the financial and operational results in our cylinder exchange business and our NGL sales business. For the years ended December 31, 2013 and 2012, we sold approximately 61% and 58%, respectively, of the propane volumes in our cylinder exchange and NGL sales businesses during the first and fourth quarters of the year.
The butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.
Weather
Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Accordingly, the volume of propane used by our customers for this purpose is affected by the severity of winter weather in the regions we serve and can vary substantially from year to year while general economic conditions in the United States and the wholesale price of propane can have a significant impact on the correlation between weather and customer demand. For the twelve months ended December 31, 2013, the weather in Texas, Oklahoma, New Mexico, Arizona, Arkansas
102
and Missouri, the six states in which our NGL sales business operates, was consistent with the average temperature as measured by the number of heating degree days reported by the NOAA. If these six states were to experience a cooling trend, we could expect demand for propane to increase, which could lead to greater sales and income.
Commodity Prices
We are exposed to volatility in crude oil, refined products and NGL commodity prices. We manage such exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
We do not have direct exposure to commodity price changes in our crude oil pipelines and storage segment. In our crude oil supply and logistics business, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using financial swaps. In our cylinder-exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a large majority of the forecasted volumes under our long-term contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. In our NGL transportation business, we do not take title to the products we transport and, therefore, have no direct commodity price exposure to the price of volumes transported.
Interest Rates
The credit markets experienced near-record low interest rates in recent years. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our current or prospective financing costs to increase accordingly.
Factors Affecting the Comparability of Our Financial Results
Our historical results of operations may not be comparable due to our acquisition activity. Our acquisition activity and the resulting changes to our business have significantly affected our operations over the last four years. The acquisitions of our initial crude oil supply and logistics and our crude oil pipelines and storage operations, including our fleet of crude oil transportation trucks and our crude oil storage facility in Cushing, Oklahoma and our refined products terminals, all in the second half of 2012, transformed the magnitude and scope of our business and provided the initial assets and operations for our crude oil supply and logistics segment, our crude oil pipelines and storage segment and our refined products terminals and storage segment. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. Please read "Business—Our Acquisition History" for greater detail about our acquisition history.
103
The following historical consolidated statement of operations data for the years ended December 31, 2013, 2012 and 2011 and the six months ended June 30, 2014 and 2013 has been derived from our audited historical consolidated financial statements and our unaudited historical condensed consolidated financial statements, respectively, included elsewhere in this prospectus.
| |
Year Ended December 31, | Six Months Ended June 30, |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
($ in thousands, except per unit amounts)
|
2011 | 2012(1)(2) | 2013(1) | 2013 | 2014 | |||||||||||
| |
|
(Restated and Recast) |
|
(unaudited) |
||||||||||||
Statement of Operations Data: |
||||||||||||||||
Total revenue |
$ | 67,156 | $ | 427,581 | $ | 2,102,233 | $ | 987,804 | $ | 865,817 | ||||||
Costs and expenses: |
||||||||||||||||
Cost of sales, excluding depreciation and amortization |
49,048 | 368,791 | 1,964,631 | 918,957 | 798,193 | |||||||||||
Operating expenses |
9,584 | 28,640 | 61,925 | 28,202 | 35,266 | |||||||||||
General and administrative |
6,053 | 20,983 | 45,284 | 20,313 | 23,879 | |||||||||||
Depreciation and amortization |
2,841 | 13,856 | 33,345 | 15,186 | 20,165 | |||||||||||
Loss on disposal of assets |
68 | 1,142 | 1,492 | 998 | 661 | |||||||||||
Operating income (loss) |
(438 | ) | (5,831 | ) | (4,444 | ) | 4,148 | (12,347 | ) | |||||||
Other income (expense): |
||||||||||||||||
Interest (expense) |
(633 | ) | (3,405 | ) | (9,075 | ) | (3,815 | ) | (5,551 | ) | ||||||
Loss on extinguishment of debt |
(95 | ) | (497 | ) | — | — | (1,634 | ) | ||||||||
Other income (expense), net |
— | 247 | 688 | 195 | 504 | |||||||||||
Income (loss) before income taxes |
(1,166 | ) | (9,486 | ) | (12,831 | ) | 528 | (19,028 | ) | |||||||
Income tax (expense) |
(35 | ) | (222 | ) | (208 | ) | (305 | ) | (156 | ) | ||||||
Net income (loss) from continuing operations |
(1,201 | ) | (9,708 | ) | (13,039 | ) | 223 | (19,184 | ) | |||||||
Net income (loss) from discontinued operations(3) |
— | 1,320 | (1,182 | ) | (23 | ) | (9,608 | ) | ||||||||
Net income (loss) |
$ | (1,201 | ) | $ | (8,388 | ) | $ | (14,221 | ) | $ | 200 | $ | (28,792 | ) | ||
- (1)
- Our
historical combined consolidated financial and operating data for the years ended December 31, 2012 and 2013 have been retrospectively adjusted
for the JP Development Dropdown. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development
Acquisition and Recast of Historical Financial Statements."
- (2)
- Our
previously issued audited consolidated financial statements as of December 31, 2012 and results of operations for the year ended
December 31, 2012 contained errors. We evaluated those errors and determined that the impact of these errors was material to our financial position as of December 31, 2012 and results of
operations for the year ended December 31, 2012. Accordingly, our previously audited consolidated balance sheet at December 31, 2012 and statement of operations and statements of
partners' capital and cash flows for the year ended December 31, 2012 have been restated to reflect the correction of the errors, including the correction of immaterial errors. Please read
note 3 of our consolidated financial statements included elsewhere in this prospectus.
- (3)
- In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
104
Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
| |
Six months ended June 30, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands) |
2013 | 2014 | Change | |||||||
Segment Adjusted EBITDA |
||||||||||
Crude oil pipelines and storage(1) |
$ | 6,023 | $ | 10,146 | $ | 4,123 | ||||
Crude oil supply and logistics(1) |
8,496 | 1,658 | (6,838 | ) | ||||||
Refined products terminaling and storage(1) |
8,827 | 5,141 | (3,686 | ) | ||||||
NGLs distribution and sales(1) |
11,150 | 7,646 | (3,504 | ) | ||||||
Discontinued operations(2) |
1,577 | 983 | (594 | ) | ||||||
Corporate and other |
(12,218 | ) | (13,536 | ) | (1,318 | ) | ||||
Total Adjusted EBITDA |
23,855 | 12,038 | (11,817 | ) | ||||||
Depreciation and amortization |
(15,186 | ) | (20,165 | ) | (4,979 | ) | ||||
Interest expense |
(3,815 | ) | (5,551 | ) | (1,736 | ) | ||||
Loss on extinguishment of debt |
— | (1,634 | ) | (1,634 | ) | |||||
Income tax expense |
(305 | ) | (156 | ) | 149 | |||||
Loss on disposal of assets |
(998 | ) | (661 | ) | 337 | |||||
Unit-based compensation |
(371 | ) | (584 | ) | (213 | ) | ||||
Total gain (loss) on commodity derivatives |
(610 | ) | 32 | 642 | ||||||
Net cash (receipts) payments for commodity derivatives settled during the period |
518 | (588 | ) | (1,106 | ) | |||||
Discontinued operations |
(1,600 | ) | (10,591 | ) | (8,991 | ) | ||||
Transaction costs and other non-cash items |
(1,288 | ) | (932 | ) | 356 | |||||
Net income (loss) |
$ | 200 | $ | (28,792 | ) | $ | (28,992 | ) | ||
- (1)
- See
further analysis of the Adjusted EBITDA of each reportable segment below.
- (2)
- In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Discontinued operations Adjusted EBITDA. Adjusted EBITDA related to the Bakken business included previously in our crude oil supply and logistics segment decreased to $1.0 million for the six months ended June 30, 2014 from $1.6 million for the six months ended June 30, 2013. The decrease was primarily due to a decrease in transported crude oil volumes of our Bakken crude oil logistics business. Due to increased competition and rising employee costs in the region, in June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.
Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses increased to $13.5 million for the six months ended June 30, 2014 from $12.2 million for the six months ended June 30, 2013. The increase was primarily due to an increase in payroll and benefits expenses of $3.0 million related to the addition of corporate office personnel to support the growth of our business. This increase was offset by a decrease in professional fees of $1.8 million related to audit, consulting and legal expenses incurred.
Depreciation and amortization expense. Depreciation and amortization expense for the six months ended June 30, 2014 increased to $20.2 million from $15.2 million for the six months ended June 30, 2013. The increase was primarily due to four acquisitions completed during or after July 2013. These acquisitions accounted for six months of depreciation and amortization activity in the six months ended June 30, 2014, which was not included in our financial results for the six months ended June 30, 2013.
105
Our property, plant and equipment base increased from $182.9 million as of June 30, 2013 to $232.7 million as of June 30, 2014. Intangible assets subject to amortization increased from $106.8 million as of June 30, 2013 to $157.5 million as of June 30, 2014.
Interest expense. Interest expense for the six months ended June 30, 2014 increased to $5.6 million from $3.8 million for the six months ended June 30, 2013 due primarily to an increase in average borrowings from $169.2 million in the six months ended June 30, 2013 to $202.3 million in the six months ended June 30, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $1.6 million for the six months ended June 30, 2014 relates to the write off of deferred financing costs associated with extinguishment of our 2011 revolving credit facility.
Loss on disposal of assets. Loss on disposal of assets for the six months ended June 30, 2014 decreased to $0.7 million from $1.0 million for the six months ended June 30, 2013. The decrease is primarily due to a decrease in the write off of scrapped cylinder and valve assets associated with our cylinder exchange business.
Total gain (loss) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period. The sum of the total gain (loss) on commodity derivatives and net cash (receipts) payments for commodity derivatives settled during the period represents the total non-cash gain (loss) on commodity derivatives that was recognized in our statements of operations but excluded from our Adjusted EBITDA calculation. Total non-cash loss on commodity derivatives increased to $0.6 million for the six months ended June 30, 2014 from $0.1 million for the six months ended June 30, 2013. The increase is due to the less favorable position of our propane hedges during the six months ended June 30, 2014 compared to the six months ended June 30, 2013.
Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense and loss on disposal of assets related to the Bakken Business previously owned by our crude oil supply and logistics segment. Such expenses increased to $10.6 million for the six months ended June 30, 2014 from $1.6 million for the six months ended June 30, 2013. The increase was primarily due to the loss on the disposal of our Bakken Business of $7.3 million in the six months ended June 30, 2014. In addition, immediately prior to the sale, we allocated $2.0 million of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that we retained. The $2.0 million allocation contributed to the overall loss from discontinued operations.
Transaction costs and other non-cash items. Transaction costs and other non-cash items decreased for the six months ended June 30, 2014 to $0.9 million from $1.3 million for the six months end June 30, 2013 primarily due to a decrease in transaction costs of $0.7 million related to audit fees incurred as a result of our 2012 acquisitions. The decrease was partially offset by an increase in non-cash vacation expenses of $0.4 million related to the addition of corporate office personnel to support the growth of our business.
106
Crude Oil Pipelines and Storage
| |
Six months ended June 30, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2013 | 2014 | Change | |||||||
Volumes: |
||||||||||
Crude oil pipeline throughput (Bbl/d)(1) |
— | (2) | 19,652 | — | (2) | |||||
Revenues: |
||||||||||
Crude oil sales |
$ | — | $ | 27,815 | $ | 27,815 | ||||
Gathering, transportation and storage fees |
7,200 | 11,791 | 4,591 | |||||||
Other revenues |
— | 819 | 819 | |||||||
Total Revenues |
7,200 | 40,425 | 33,225 | |||||||
Cost of sales, excluding depreciation and amortization(3)(4) |
— |
(28,058 |
) |
(28,058 |
) |
|||||
Adjusted gross margin |
7,200 | 12,367 | 5,167 | |||||||
Operating expenses(4) |
(1,230 | ) | (1,935 | ) | (705 | ) | ||||
General and administrative(4) |
53 | (286 | ) | (339 | ) | |||||
Segment Adjusted EBITDA |
$ | 6,023 | $ | 10,146 | $ | 4,123 | ||||
- (1)
- Represents
the average daily throughput volume of our crude oil pipelines operations. The volumes in our crude oil storage operations have no effect on
operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.
- (2)
- Not
applicable because the Silver Dollar Pipeline System was acquired by JP Development in October 2013.
- (3)
- Includes
intersegment cost of sales, excluding depreciation and amortization of $25.2 million in the six months ended June 30, 2014. The
intersegment cost of sales, excluding depreciation and amortization were eliminated upon consolidation.
- (4)
- Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $12.4 million for the six months ended June 30, 2014 from $7.2 million for the six months ended June 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System.
Operating expenses. Operating expenses increased to $1.9 million for the six months ended June 30, 2014 from $1.2 million for the six months ended June 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013.
General and administrative. General and administrative increased to $0.3 million for the six months ended June 30, 2014 from $0.1 million for the six months ended June 30, 2013. The increase was due to the acquisition of Wildcat Permian in October 2013.
107
Crude Oil Supply and Logistics
| |
Six months ended June 30, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2013 | 2014 | Change | |||||||
Volumes: |
||||||||||
Crude oil sales (Bbls/d)(1) |
51,372 | 42,411 | (8,961 | ) | ||||||
Revenues: |
||||||||||
Crude oil sales(2) |
$ | 877,318 | $ | 723,227 | $ | (154,091 | ) | |||
Gathering, transportation and storage fees |
848 | 5,945 | 5,097 | |||||||
Other revenues |
107 | 58 | (49 | ) | ||||||
Total Revenues |
878,273 | 729,230 | (149,043 | ) | ||||||
Cost of sales, excluding depreciation and amortization(3) |
(865,035 |
) |
(722,756 |
) |
142,279 |
|||||
Adjusted gross margin |
13,238 | 6,474 | (6,764 | ) | ||||||
Operating expenses(3) |
(3,424 |
) |
(3,117 |
) |
307 |
|||||
General and administrative(3) |
(1,318 | ) | (1,731 | ) | (413 | ) | ||||
Other income (expenses) |
— | 32 | 32 | |||||||
Segment Adjusted EBITDA |
$ | 8,496 | $ | 1,658 | $ | (6,838 | ) | |||
- (1)
- Represents
the average daily sales volume in our crude oil supply and logistics operations.
- (2)
- Includes
intersegment revenues of $25.2 million in the six months ended June 30, 2014. The intersegment revenues were eliminated upon
consolidation.
- (3)
- Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Volumes. Crude oil sales volumes decreased to 42,411 barrels per day for the six months ended June 30, 2014 from 51,372 barrels per day for the six months ended June 30, 2013. The decrease was primarily due to increased competition in the Mid-Continent area.
Adjusted gross margin. Adjusted gross margin decreased to $6.5 million for the six months ended June 30, 2014 from $13.2 million for the six months ended June 30, 2013. The decrease was primarily due to unfavorable market conditions for blending crude oil in our storage tanks at Cushing ($4.4 million) as well as a decrease in sales volumes ($2.3 million) as explained above.
108
Refined Products Terminals and Storage
| |
Six months ended June 30, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2013 | 2014 | Change | |||||||
Volumes: |
||||||||||
Terminal and storage throughput (Mgal/d)(1) |
2,834 | 2,699 | (135 | ) | ||||||
Revenues: |
||||||||||
Refined product sales |
$ | 7,159 | $ | 8,275 | $ | 1,116 | ||||
Refined products terminals and storage fees |
5,964 | 5,614 | (350 | ) | ||||||
Total Revenues |
13,123 | 13,889 | 766 | |||||||
Cost of sales, excluding depreciation and amortization(2) |
(2,873 |
) |
(4,083 |
) |
(1,210 |
) |
||||
Adjusted gross margin |
10,250 | 9,806 | (444 | ) | ||||||
Operating expenses(2) |
(1,216 |
) |
(4,000 |
) |
(2,784 |
) |
||||
General and administrative(2) |
(207 | ) | (671 | ) | (464 | ) | ||||
Other income (expenses) |
— | 6 | 6 | |||||||
Segment Adjusted EBITDA |
$ | 8,827 | $ | 5,141 | $ | (3,686 | ) | |||
- (1)
- Represents
the average daily throughput volume in our refined products terminals and storage segment.
- (2)
- Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Revenues. Revenues increased to $13.9 million for the six months ended June 30, 2014 from $13.1 million for the six months ended June 30, 2013. The increase was primarily due to a $0.9 million increase in revenue at our Caddo Mills terminal from the addition of conventional blendstocks for oxygenate blending ("CBOB") in late December 2013.
Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization increased to $4.1 million for the six months ended June 30, 2014 from $2.9 million for the six months ended June 30, 2013. The increase was primarily due to the addition of CBOB blending at our Caddo Mills terminal in late December 2013, which resulted in additional cost of sales for the six months ended June 30, 2014 that were not included in the six months ended June 30, 2013.
Operating expenses. Operating expenses increased to $4.0 million for the six months ended June 30, 2014 from $1.2 million for the six months ended June 30, 2013. The increase was primarily due to the recording of a charge of $2.7 million at our North Little Rock, Arkansas terminal in June 2014. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal under-delivered refined products to its customers and consequently, recognized excessive gains on refined products generated during the terminal's normal terminal and storage process. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. We estimated the volume of refined products to be returned to customers of approximately 24,000 barrels, which amounts to an estimated value of $2.7 million as of June 30, 2014. Accordingly, we recorded this charge to operating expenses in the consolidated statement of operations for the six months ended June 30, 2014 and will update the estimated accrual each reporting period based on
109
changes in estimate related to volumes returned, market prices and other changes. We intend to return the estimated refined products during the fourth quarter of 2014.
General and administrative. General and administrative increased to $0.7 million for the six months ended June 30, 2014 from $0.2 million for the six months ended June 30, 2013. The increase was primarily due to an increase in employee salary and benefit expenses of $0.4 million related to the addition of personnel to support the growth of our refined products terminals and storage business.
NGL Distribution and Sales
| |
Six months ended June 30, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2013 | 2014 | Change | |||||||
Volumes: |
||||||||||
NGL and refined product sales (Gal/d)(1) |
182,463 | 199,016 | 16,553 | |||||||
Revenues: |
||||||||||
Gathering, transportation and storage fees |
$ | — | $ | 2,650 | $ | 2,650 | ||||
NGL and refined product sales |
83,340 | 98,822 | 15,482 | |||||||
Other revenues |
5,868 | 6,028 | 160 | |||||||
Total Revenues |
89,208 | 107,500 | 18,292 | |||||||
Cost of sales, excluding depreciation and amortization(2) |
(50,958 |
) |
(67,594 |
) |
(16,636 |
) |
||||
Adjusted gross margin |
38,250 | 39,906 | 1,656 | |||||||
Operating expenses(2) |
(21,964 |
) |
(25,746 |
) |
(3,782 |
) |
||||
General and administrative(2) |
(5,336 | ) | (6,837 | ) | (1,501 | ) | ||||
Other income (expenses) |
200 | 323 | 123 | |||||||
Segment Adjusted EBITDA |
$ | 11,150 | $ | 7,646 | $ | (3,504 | ) | |||
- (1)
- Represents
the average daily sales volume in our NGL distribution and sales segment.
- (2)
- Certain non-cash or non-recurring expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Revenues. Revenues increased to $107.5 million for the six months ended June 30, 2014 from $89.2 million for the six months ended June 30, 2013. The major components of this increase were as follows:
- •
- an increase in NGL and refined product sales as a result of an increase in the average price of propane
($8.8 million) as well as an increase in sales volumes ($7.6 million). Average daily propane commodity prices during the six months ended June 30, 2014 at Mont Belvieu, Texas, one
of the major supply points in the U.S., were approximately 33% higher than such prices during the six months ended June 30, 2013. In addition, sales volumes increased as a result of colder
temperatures and the acquisition of BMH Propane, LLC ("BMH") in July 2013. The average temperature as measured by the number of heating degree days reported by the NOAA was 0.1% colder in areas
in which we operate for the six months ended June 30, 2014 compared to the six months ended June 30, 2013; and
- •
- the acquisition of Highway Pipeline, Inc. ("HPI") in October 2013, which generated $2.7 million of revenues in the six months ended June 30, 2014, compared to $0 in the six months ended June 30, 2013.
110
Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization increased to $67.6 million for the six months ended June 30, 2014 from $51.0 million for the six months ended June 30, 2013. The increase was primarily due to an increase in the average cost of propane ($12.0 million) as well as an increase in sales volumes ($3.3 million) compared to the six months ended June 30, 2013 as described above.
Operating expenses. Operating expenses increased to $25.7 million for the six months ended June 30, 2014 from $22.0 million for the six months ended June 30, 2013. The major components of this increase were as follows:
- •
- the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $1.4 million of
operating expenses in the six months ended June 30, 2014, compared to $0 in the six months ended June 30, 2013;
- •
- increase in employee cost of approximately $0.2 million, as a result of the increase in headcount to support our
growing business;
- •
- increase in propane cylinder repairs and maintenance expenses of approximately $0.7 million, as a result of the
increase in propane cylinder exchanges; and
- •
- increase in business insurance expenses of approximately $0.7 million, as a result of the western expansion of our cylinder exchange business.
General and administrative. General and administrative increased to $6.8 million for the six months ended June 30, 2014 from $5.3 million for the six months ended June 30, 2013. The major components of this increase were as follows:
- •
- the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $0.6 million of
general and administrative expenses in the six months ended June 30, 2014, compared to $0 in the six months ended June 30, 2013;
- •
- increase in employee costs of approximately $0.7 million, as a result of the increase in headcount to support our
growing business; and
- •
- increase in office expenses of $0.3 million, to support our growing business.
111
Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands) |
2012 | 2013 | Change | |||||||
| |
(Restated and Recast) |
|
|
|||||||
Segment Adjusted EBITDA |
||||||||||
Crude oil pipelines and storage(1) |
$ | 4,836 | $ | 13,353 | $ | 8,517 | ||||
Crude oil supply and logistics(1) |
(40 | ) | 14,686 | 14,726 | ||||||
Refined products terminaling and storage(1) |
1,161 | 16,100 | 14,939 | |||||||
NGLs distribution and sales(1) |
14,022 | 15,518 | 1,496 | |||||||
Discontinued operations |
2,755 | 2,023 | (732 | ) | ||||||
Corporate and other |
(8,174 | ) | (27,396 | ) | (19,222 | ) | ||||
Total Adjusted EBITDA |
14,560 | 34,284 | 19,724 | |||||||
Depreciation and amortization |
(13,856 | ) | (33,345 | ) | (19,489 | ) | ||||
Interest expense |
(3,405 | ) | (9,075 | ) | (5,670 | ) | ||||
Loss on extinguishment of debt |
(497 | ) | — | 497 | ||||||
Income tax expense |
(222 | ) | (208 | ) | 14 | |||||
Loss on disposal of assets |
(1,142 | ) | (1,492 | ) | (350 | ) | ||||
Unit-based compensation |
(2,485 | ) | (948 | ) | 1,537 | |||||
Total gain on commodity derivatives |
640 | 902 | 262 | |||||||
Net cash payments for commodity derivatives settled during the period |
946 | 209 | (737 | ) | ||||||
Discontinued operations |
(1,435 | ) | $ | (3,205 | ) | $ | (1,770 | ) | ||
Transaction costs and other non-cash items |
(1,492 | ) | (1,343 | ) | 149 | |||||
Net loss |
$ | (8,388 | ) | $ | (14,221 | ) | $ | (5,833 | ) | |
- (1)
- See further analysis of the Adjusted EBITDA of each reportable segment below.
Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses increased to $27.4 million for the year ended December 31, 2013 from $8.2 million for the year ended December 31, 2012. The increase was primarily due to an increase in professional fees of $11.1 million related to audit, consulting and legal expenses incurred as a result of the initial public offering process which commenced during the year ended December 31, 2013. The remaining increase of $8.1 million is due to increased payroll and benefits expenses related to the addition of corporate office personnel to support the growth of our business.
Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2013 increased to $33.3 million from $13.9 million for the year ended December 31, 2012. The increase was primarily due to six significant acquisitions completed during or after June 2012. These acquisitions accounted for at least five more months of depreciation and amortization activity in 2013, which was not included in our 2012 financial results. Our property, plant and equipment base increased from $191.9 million as of December 31, 2012 to $238.1 million as of December 31, 2013. Intangible assets subject to amortization increased from $113.7 million as of December 31, 2012 to $175.1 million as of December 31, 2013.
Interest expense. Interest expense for the year ended December 31, 2013 increased to $9.1 million from $3.4 million for the year ended December 31, 2012 due primarily to an increase in average borrowings from $63.7 million in 2012 to $172.3 million in 2013.
112
Loss on disposal of assets. Loss on disposal of assets for the year ended December 31, 2013 increased to $1.5 million from $1.1 million for the year ended December 31, 2012. The increase is primarily due to an increase in the write off of scrapped cylinder and valve assets associated with our cylinder exchange business acquired in June 2012.
Unit-based compensation. Unit-based compensation for the year ended December 31, 2013 decreased to $0.9 million from $2.5 million for the year ended December 31, 2012. The decrease was primarily due to the vesting of certain performance awards in 2012, while no such vesting occurred in 2013.
Total gain on commodity derivatives and net cash payments for commodity derivatives settled during the period. The sum of the total gain on commodity derivatives and net cash payments for commodity derivatives settled during the period represents the total non-cash gain on commodity derivatives that was recognized in our statements of operations but excluded from our Adjusted EBITDA calculation. Total non-cash gain on commodity derivatives decreased to $1.1 million for the year ended December 31, 2013 from $1.6 million for the year ended December 31, 2012. The decrease is due to the less favorable position of our propane hedges during the year ended December 31, 2013 compared to the year ended December 31, 2012.
Crude Oil Pipelines and Storage
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2012 | 2013 | Change | |||||||
| |
(Restated and Recast) |
|
|
|||||||
Volumes: |
||||||||||
Crude oil pipeline throughput (Bbl/d)(1) |
— | (2) | 13,738 | — | (2) | |||||
Revenues: |
||||||||||
Crude oil sales |
$ | — | $ | 9,001 | $ | 9,001 | ||||
Gathering, transportation and storage fees |
6,000 | 16,100 | 10,100 | |||||||
Other revenues |
224 | 300 | 76 | |||||||
Total Revenues |
6,224 | 25,401 | 19,177 | |||||||
Cost of sales, excluding depreciation and amortization(3) |
(224 |
) |
(8,894 |
) |
(8,670 |
) |
||||
Adjusted gross margin |
6,000 | 16,507 | 10,507 | |||||||
Operating expenses(4) |
(1,072 | ) | (3,044 | ) | (1,972 | ) | ||||
General and administrative(4) |
(92 | ) | (110 | ) | (18 | ) | ||||
Segment Adjusted EBITDA |
$ | 4,836 | $ | 13,353 | $ | 8,517 | ||||
- (1)
- Represents
the average daily throughput volume of our crude oil pipelines operations from the date of acquisition of October 7, 2013 through
December 31, 2013. The volumes in our crude oil storage operations have no effect on operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.
- (2)
- Not
applicable because the Silver Dollar Pipeline System was acquired by JP Development in October 2013.
- (3)
- Includes intersegment cost of sales, excluding depreciation and amortization, of $5.6 million in 2013. The intersegment cost of sales, excluding depreciation and amortization, were eliminated upon consolidation.
113
- (4)
- Certain non-cash or non-recurring expenses have been excluded from operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Adjusted gross margin. Adjusted gross margin increased to $16.5 million for the year ended December 31, 2013 from $6.0 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System. Adjusted gross margin
attributed to the Silver Dollar Pipeline System for the period from October to December 2013 were approximately $2.1 million; and
- •
- the acquisition of Parnon Storage in August 2012, which generated a full year of adjusted gross margin of approximately $14.4 million in 2013, compared to adjusted gross margin during a five-month period in 2012 of approximately $6.0 million.
Operating expenses. Operating expenses increased to $3.0 million for the year ended December 31, 2013 from $1.1 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Wildcat Permian in October 2013. Operating expense attributed to Wildcat Permian for the period from
October to December 2013 was approximately $0.3 million; and
- •
- the acquisition of Parnon Storage in August 2012, which incurred a full year of operating expense of approximately $2.7 million in 2013, compared to operating expense during a five-month period in 2012 of approximately $1.1 million.
Crude Oil Supply and Logistics
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2012 | 2013 | Change | |||||||
| |
(Restated and Recast) |
|
|
|||||||
Volumes: |
||||||||||
Crude oil sales (Bbls/d)(1) |
24,201 | 53,471 | 29,270 | |||||||
Revenues |
||||||||||
Crude oil sales(2) |
$ | 290,253 | $ | 1,871,965 | $ | 1,581,712 | ||||
Gathering, transportation and storage fees |
2,244 | 6,432 | 4,188 | |||||||
Other revenues |
120 | 133 | 13 | |||||||
Total Revenues |
292,617 | 1,878,529 | 1,585,912 | |||||||
Cost of sales, excluding depreciation and amortization |
(289,275 |
) |
(1,852,249 |
) |
(1,562,974 |
) |
||||
Adjusted gross margin |
3,342 | 26,280 | 22,938 | |||||||
Operating expenses(3) |
(2,464 |
) |
(8,501 |
) |
(6,037 |
) |
||||
General and administrative(3) |
(855 | ) | (3,095 | ) | (2,240 | ) | ||||
Other income (expenses) |
(63 | ) | 2 | 65 | ||||||
Segment Adjusted EBITDA |
$ | (40 | ) | $ | 14,686 | $ | 14,726 | |||
- (1)
- Represents
the average daily sales volume in our crude oil supply and logistics operations.
- (2)
- Includes
intersegment revenues of $5.6 million in 2013. The intersegment revenues were eliminated upon consolidation.
- (3)
- Certain non-cash or non-recurring expenses have been excluded from operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
114
Volumes. The increase in daily crude oil sales volume is primarily attributable to JP Development's completion of the construction of the Great Salt Plains Pipeline System in October 2012. The pipeline system became operational in October 2012, which enabled our crude oil supply business to handle greater quantities through the pipeline.
Adjusted gross margin. Adjusted gross margin increased to $26.3 million for the year ended December 31, 2013 from $3.3 million for the year ended December 31, 2012 due primarily to the acquisition of the crude oil supply and logistics business of Parnon Gathering in August 2012, which generated a full year of adjusted gross margin of approximately $23.7 million in 2013, compared to adjusted gross margin during a five-month period in 2012 of approximately $2.7 million.
Operating expenses. Operating expenses increased to $8.5 million for the year ended December 31, 2013 from $2.5 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of the crude oil supply and logistics business of Parnon Gathering in August 2012, which incurred a full
year of operating expenses of approximately $6.8 million in 2013, compared to operating expenses during a five-month period in 2012 of approximately $1.8 million; and
- •
- the acquisition of Falco in late July 2012, which incurred a full year of operating expenses of approximately $1.6 million in 2013, compared to operating expenses during a five-month period in 2012 of approximately $0.7 million.
General and administrative. General and administrative expenses increased to $3.1 million for the year ended December 31, 2013 from $0.9 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of the crude oil supply and logistics business of Parnon Gathering in August 2012, which incurred a full
year of general and administrative expenses of approximately $1.8 million in 2013, compared to general and administrative expenses during a five-month period in 2012 of approximately
$0.6 million; and
- •
- the acquisition of Falco Energy in late July 2012, which incurred a full year of general and administrative expenses of approximately $1.3 million in 2013, compared to general and administrative expenses during a five-month period in 2012 of approximately $0.3 million.
115
Refined Products Terminals and Storage
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2012 | 2013 | Change | |||||||
| |
(Restated and Recast) |
|
|
|||||||
Volumes: |
||||||||||
Terminal and storage throughput (Mgal/d)(1) |
2,400 | 2,901 | 501 | |||||||
Revenues: |
||||||||||
Refined product sales |
$ | 1,723 | $ | 11,702 | $ | 9,979 | ||||
Refined products terminals and storage fees |
983 | 12,308 | 11,325 | |||||||
Total Revenues |
2,706 | 24,010 | 21,304 | |||||||
Cost of sales, excluding depreciation and amortization |
(974 |
) |
(4,683 |
) |
(3,709 |
) |
||||
Adjusted gross margin |
1,732 | 19,327 | 17,595 | |||||||
Operating expenses(2) |
(280 | ) | (2,464 | ) | (2,184 | ) | ||||
General and administrative(2) |
(292 | ) | (771 | ) | (479 | ) | ||||
Other income (expenses) |
1 | 8 | 7 | |||||||
Segment Adjusted EBITDA |
$ | 1,161 | $ | 16,100 | $ | 14,939 | ||||
- (1)
- Represents
the average daily throughput volume in our refined products terminals and storage segment.
- (2)
- Certain non-cash or non-recurring expenses have been excluded from operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Reason for the year-over-year increase in revenues, cost of sales, excluding depreciation and amortization, operating expenses, and general and administrative expenses. We acquired our refined products terminals and storage operations on November 27, 2012. As a result, the revenues, costs of sales, operating expenses and general and administrative expenses for the year ended December 31, 2013 contain approximately eleven more months of activity than the year ended December 31, 2012.
116
NGL Distribution and Sales
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2012 | 2013 | Change | |||||||
| |
(Restated and Recast) |
|
|
|||||||
Volumes: |
||||||||||
NGL and refined product sales (Gal/d)(1) |
128,775 | 180,850 | 52,075 | |||||||
Revenues: |
||||||||||
Gathering, transportation and storage fees |
$ | — | $ | 1,614 | $ | 1,614 | ||||
NGL and refined product sales |
117,392 | 166,880 | 49,488 | |||||||
Other revenues |
8,641 | 11,371 | 2,730 | |||||||
Total Revenues |
126,033 | 179,865 | 53,832 | |||||||
Cost of sales, excluding depreciation and amortization(2) |
(79,904 |
) |
(105,488 |
) |
(25,584 |
) |
||||
Adjusted gross margin |
46,129 | 74,377 | 28,248 | |||||||
Operating Expenses(2) |
(24,746 | ) | (47,307 | ) | (22,561 | ) | ||||
General and administrative(2) |
(7,639 | ) | (11,688 | ) | (4,049 | ) | ||||
Other income (expenses) |
278 | 136 | (142 | ) | ||||||
Segment Adjusted EBITDA |
$ | 14,022 | $ | 15,518 | $ | 1,496 | ||||
- (1)
- Represents
the average daily sales volume in our NGL distribution and sales segment.
- (2)
- Certain non-cash or non-recurring expenses have been excluded from operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Volumes. The increase in our daily NGL and refined products sales volume from 2012 to 2013 was primarily caused by the various acquisitions described below.
Revenues. Revenues increased to $179.9 million for the year ended December 31, 2013 from $126.0 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012, which generated a full year of revenues of approximately
$58.3 million in 2013, compared to revenues during a seven-month period in 2012 of approximately $31.8 million;
- •
- the acquisitions of SemStream and Tri-State in the fourth quarter of 2012, BMH in July 2013, and HPI in October 2013,
which generated $23.7 million of revenues in 2013, compared to $0 in 2012; and
- •
- general customer and business growth in 2013.
Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization increased to $105.5 million for the year ended December 31, 2013 from $79.9 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012, which had a full year of cost of sales, excluding depreciation
and amortization, of approximately $20.7 million in 2013, compared to cost of sales, excluding depreciation and amortization, during a seven-month period in 2012 of approximately
$11.9 million;
- •
- the acquisitions of SemStream and Tri-State in the fourth quarter of 2012, BMH in July 2013, and HPI in October 2013, which accounted for $16.9 million of cost of sales, excluding depreciation and amortization, in 2013, compared to $0 in 2012; and
117
- •
- general customer and business growth in 2013.
Operating expenses. Operating expenses increased to $47.3 million for the year ended December 31, 2013 from $24.7 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012, which incurred a full year of operating expenses of
approximately $28.3 million in 2013, compared to operating expenses in 2012 during a seven-month period of approximately $12.9 million;
- •
- the acquisitions of SemStream and Tri-State at year-end of 2012, BMH in July 2013, and HPI in October 2013, which resulted
in $3.6 million of operating expenses in 2013, compared to $0 in 2012; and
- •
- an increase in employee cost of approximately $2.4 million, as a result of the increase in headcount to support the fast growing business.
General and administrative. General and administrative expenses increased to $11.7 million for the year ended December 31, 2013 from $7.6 million for the year ended December 31, 2012. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012, which incurred a full year of general and administrative
expenses of approximately $5.1 million in 2013, compared to general and administrative expenses during a seven-month period in 2012 of approximately $3.4 million; and
- •
- the acquisitions of SemStream and Tri-State in the fourth quarter of 2012, BMH in July 2013, and HPI in October 2013, which resulted in $0.6 million of general and administrative expenses in 2013, compared to $0 in 2012.
118
Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands) |
2011 | 2012 | Change | |||||||
| |
|
(Restated and Recast) |
|
|||||||
Segment Adjusted EBITDA |
||||||||||
Crude oil pipelines and storage(1) |
$ | — | $ | 4,836 | $ | 4,836 | ||||
Crude oil supply and logistics(1) |
— | (40 | ) | (40 | ) | |||||
Refined products terminaling and storage(1) |
— | 1,161 | 1,161 | |||||||
NGLs distribution and sales(1) |
6,494 | 14,022 | 7,528 | |||||||
Discontinued operations |
— | 2,755 | 2,755 | |||||||
Corporate and other |
(3,669 | ) | (8,174 | ) | (4,505 | ) | ||||
Total Adjusted EBITDA |
2,825 | 14,560 | 11,735 | |||||||
Depreciation and amortization |
(2,841 | ) | (13,856 | ) | (11,015 | ) | ||||
Interest expense |
(633 | ) | (3,405 | ) | (2,772 | ) | ||||
Loss on extinguishment of debt |
(95 | ) | (497 | ) | (402 | ) | ||||
Income tax expense |
(35 | ) | (222 | ) | (187 | ) | ||||
Loss on disposal of assets |
(68 | ) | (1,142 | ) | (1,074 | ) | ||||
Unit-based compensation |
— | (2,485 | ) | (2,485 | ) | |||||
Total gain on commodity derivatives |
— | 640 | 640 | |||||||
Net cash payments for commodity derivatives settled during the period |
— | 946 | 946 | |||||||
Discontinued operations |
— | (1,435 | ) | (1,435 | ) | |||||
Transaction costs and other non-cash items |
(354 | ) | (1,492 | ) | (1,138 | ) | ||||
Net loss |
$ | (1,201 | ) | $ | (8,388 | ) | $ | (7,187 | ) | |
- (1)
- See further analysis of the Adjusted EBITDA of each reportable segment below.
Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses increased to $8.2 million for the year ended December 31, 2012 from $3.7 million for the year ended December 31, 2011. The increase was primarily due to increased payroll and consulting expenses related to the addition of corporate office personnel to support our growing business.
Depreciation and amortization. Depreciation and amortization expense for the year ended December 31, 2012 increased to $13.9 million from $2.8 million for the year ended December 31, 2011. The increase was primarily due to six acquisitions made during or prior to August 2012. This provided at least five months of depreciation and amortization expense activity that was included in our results for the year ended December 31, 2012, but was not included in our operations for the year ended December 31, 2011. Our depreciation and amortization expense for the year ended December 31, 2012 also included a full twelve months of activity related to seven acquisitions completed from June 2011 through the end of 2011, which is consistent with the increase in our depreciable and amortizable assets. Our property plant and equipment base increased from $27.7 million as of December 31, 2011 to $191.9 million as of December 31, 2012. Intangible assets subject to amortization increased from $10.9 million as of December 31, 2011 to $113.7 million as of December 31, 2012.
Interest expense. Interest expense for the year ended December 31, 2012 increased to $3.4 million from $0.6 million for the year ended December 31, 2011. The increase was primarily due to additional borrowings related to five acquisitions made during 2012. As of December 31, 2012, we had
119
$167.7 million of total long-term debt (including current maturities) outstanding compared to $16.9 million as of December 31, 2011. The increase of $150.8 million was due primarily to an increase in borrowings under our 2011 revolving credit facility from $15.3 million as of December 31, 2011 to $157.4 million as of December 31, 2012. Additionally, we assumed additional debt of $7.7 million in connection with an acquisition in August 2012.
Loss on disposal of assets. Loss on disposal of assets for the year ended December 31, 2012 increased to $1.1 million from $0.1 million for the year ended December 31, 2011. The increase is primarily related to the write off of scrapped cylinder and valve assets associated with our cylinder exchange business. We acquired this business in June 2012 therefore, our 2011 results do not include any related loss on disposal of such assets.
Unit-based compensation. We did not issue any restricted common units in 2011, therefore, we did not record any unit-based compensation expense in 2011.
Total gain on commodity derivatives and net cash payments for commodity derivatives settled during the period. The sum of the total gain on commodity derivatives and net cash payments for commodity derivatives settled during the period represents the total non-cash gain on commodity derivatives that was recognized in the statements of operations but needs to be excluded from the Adjusted EBITDA calculation. We did not utilize commodity hedges during the year ended December 31, 2011.
Transaction costs and other non-cash items. Transaction costs and other non-cash items increased for the year ended December 31, 2012 to $1.5 million from $0.4 million for the year-end December 31, 2011. The increase was due primarily to the increase in the size of the companies we acquired in 2012 compared to 2011. We completed nine acquisitions during 2012 for a total purchase price of approximately $400.1 million compared to seven acquisitions in 2011 for a total purchase price of $27.9 million.
We did not have crude oil pipelines and storage, crude oil supply and logistics, or refined products terminals and storage segments in 2011, since all the related businesses were acquired in 2012 or later. Therefore, our segment operating results discussions for the year ended December 31, 2012 compared to the year ended December 31, 2011 will only cover our NGL distribution and sales segment.
120
NGL Distribution and Sales
| |
Year Ended December 31, |
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, unless otherwise noted) |
2011 | 2012 | Change | |||||||
| |
|
(Restated and Recast) |
|
|||||||
Volumes: |
||||||||||
NGL and refined product sales (Gal/d)(1) |
61,314 | 128,775 | 67,461 | |||||||
Revenues: |
||||||||||
NGL and refined product sales |
$ | 63,190 | $ | 117,392 | $ | 54,202 | ||||
Other revenues |
3,966 | 8,641 | 4,675 | |||||||
Total Revenues |
67,156 | 126,033 | 58,877 | |||||||
Cost of sales, excluding depreciation and amortization(2) |
(49,048 |
) |
(79,904 |
) |
(30,856 |
) |
||||
Adjusted gross margin |
18,108 | 46,129 | 28,021 | |||||||
Operating expenses(2) |
(9,374 | ) | (24,746 | ) | (15,372 | ) | ||||
General and administrative(2) |
(2,240 | ) | (7,639 | ) | (5,399 | ) | ||||
Other income (expenses) |
— | 278 | 278 | |||||||
Segment Adjusted EBITDA |
$ | 6,494 | $ | 14,022 | $ | 7,528 | ||||
- (1)
- Represents
the average daily sales volume in our NGL distribution and sales segment.
- (2)
- Certain non-cash or non-recurring expenses have been excluded from operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.
Volumes. The increase in our daily NGL and refined products sales volume from 2011 to 2012 was primarily caused by the various acquisitions described below.
Revenues. Revenues increased to $126.0 million for the year ended December 31, 2012 from $67.2 million for the year ended December 31, 2011. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012. Revenue associated with Heritage Propane for the period from
June to December 2012 were $31.8 million; and
- •
- the acquisitions of seven propane distribution and sales businesses since late June of 2011. These acquisitions generated a full year of revenues in 2012, compared to less than six months of revenues in 2011.
Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization increased to $79.9 million for the year ended December 31, 2012 from $49.0 million for the year ended December 31, 2011. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012. Cost of sales, excluding depreciation and amortization,
associated with Heritage Propane for the period from June to December 2012 were $11.9 million; and
- •
- the acquisitions of seven propane distribution and sales businesses since late June of 2011. These acquisitions had a full year of cost of sales, excluding depreciation and amortization, in 2012, compared to less than six months of cost of sales, excluding depreciation and amortization, in 2011.
121
Operating expenses. Operating expenses increased to $24.7 million for the year ended December 31, 2012 from $9.4 million for the year ended December 31, 2011. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012. Operating expenses associated with Heritage Propane for the
period from June to December 2012 were $12.9 million; and
- •
- the acquisitions of seven propane distribution and sales businesses since late June of 2011. These acquisitions incurred a full year of operating expenses in 2012, compared to less than six months of operating expenses in 2011.
General and administrative. General and administrative increased to $7.6 million for the year ended December 31, 2012 from $2.2 million for the year ended December 31, 2011. The major components of this increase were as follows:
- •
- the acquisition of Heritage Propane in early June of 2012. General and administrative expenses associated with Heritage
Propane for the period from June to December 2012 were $3.4 million; and
- •
- the acquisitions of seven propane distribution and sales businesses since late June of 2011. These acquisitions incurred a full year of general and administrative expenses in 2012, compared to less than six months of general and administrative expenses in 2011.
Liquidity and Capital Resources
We principally require liquidity to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Historically, our sources of liquidity included cash generated from operations, equity investments by ArcLight and borrowings under our revolving credit facility.
Subsequent to this offering, we expect our sources of liquidity to include:
- •
- cash generated from operations;
- •
- a portion of the proceeds from this offering to replenish working capital;
- •
- borrowings under our revolving credit facility; and
- •
- issuances of debt and equity.
We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our cash distribution requirements. We believe that future internal growth projects or potential acquisitions will be funded primarily through borrowings under our revolving credit facility or through issuances of debt and equity securities.
Distributions
During the years ended December 31, 2011, 2012 and 2013 and the six months ended June 30, 2014, we paid distributions to our unitholders in the amounts of $0.8 million, $7.8 million, $17.4 million and $0, respectively. Following the completion of this offering, we intend to pay a minimum quarterly distribution of $0.3250 per unit per quarter, which equates to $11.8 million per quarter, or $47.4 million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We do not have a legal obligation to pay this distribution, except as provided in our partnership agreement. Please read "Cash Distribution Policy and Restrictions on Distributions."
2011 Revolving Credit Facility
Our 2011 revolving credit facility initially consisted of a $50.0 million revolving line of credit, which included a sub-limit of up to $2.0 million for letters of credit. Our 2011 revolving credit facility was
122
amended on June 5, 2012 to increase the commitment to $60.0 million and on September 6, 2012 to increase the commitment to $200.0 million. Substantially all of our assets were pledged as collateral under our 2011 revolving credit facility. Our 2011 revolving credit facility contained customary covenants, including, among others, those that restricted our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on our assets. We were not in compliance with certain covenants during 2012 and the first quarter of 2013, including annual reporting requirements for the fiscal year ended December 31, 2012, making acquisitions without satisfying a leverage ratio covenant and making distributions related to the third and fourth quarters of 2012 without satisfying a financial leverage covenant. In April 2013, we obtained waivers for these matters. In the third quarter of 2013, we were not in compliance with the leverage ratio covenant, which noncompliance was waived pursuant to a waiver received on December 6, 2013. On February 12, 2014, we entered into our current revolving credit facility and used the borrowings thereunder to repay all outstanding balances under our 2011 revolving credit facility.
F&M Bank Credit Agreement
On July 20, 2012, we entered into the F&M Bank credit agreement for the purchase of new, and the refinancing of existing, vehicles and equipment. The F&M Bank credit agreement consisted of several term loans collateralized by vehicles and equipment financed by the loans. The loans had an outstanding loan balance of $4,135,000 as of December 31, 2013, and were paid off in full on February 12, 2014, with borrowings under our revolving credit facility.
2014 Revolving Credit Facility
Our revolving credit facility has a maturity date of February 12, 2019 and consists of a $275.0 million revolving line of credit, which includes a sub-limit of up to $100.0 million for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275.0 million to $425.0 million, subject to obtaining additional or increased lender commitments. Our revolving credit facility is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and for general partnership purposes, including distributions, not in contravention of law or the loan documents. Substantially all of our assets, but excluding equity in and assets of unrestricted subsidiaries and other customary exclusions, are pledged as collateral under our revolving credit facility. Our revolving credit facility contains customary covenants, including, among others, those that restrict our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on our assets.
Our revolving credit facility also requires compliance with certain financial covenants, which include the following:
- •
- a consolidated interest coverage ratio of not less than 2.50;
- •
- (i) prior to our issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 4.50, which
requirement to maintain a certain consolidated total leverage ratio is subject to a provision for increases up to 5.00 in connection with certain future acquisitions that take place after the closing
of this offering and (ii) from and after our issuance of certain unsecured notes, a consolidated leverage ratio of not more than 5.00, which requirement to maintain a certain consolidated
coverage ratio is subject to increase up to 5.50 in connection with certain future acquisitions; and
- •
- from and after our issuance of certain unsecured notes, a consolidated senior secured net leverage ratio of not more than 3.50.
We were not in compliance with the leverage ratio covenant for the quarter ended June 30, 2014, which noncompliance was waived pursuant to a waiver we received on August 5, 2014. Based on preliminary estimates of the third quarter 2014, we anticipate that we will not be in compliance with
123
our leverage ratio covenant as of September 30, 2014. We obtained a waiver on September 19, 2014 that extended the measurement date to November 14, 2014. If we do not close this offering before November 14, 2014 we will be required to obtain an additional waiver from the lenders under our revolving credit facility because we anticipate that we will be in violation of the leverage ratio covenant pursuant to the terms of the September 19, 2014 waiver.
As of August 31, 2014, we had $195.6 million of outstanding borrowings under our revolving credit facility and a remaining borrowing capacity of $38.8 million thereunder. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $40.6 million as of August 31, 2014.
Borrowings under our revolving credit facility bear interest at a variable rate per annum equal to the lesser of LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin each as defined therein). As of the date of this offering, the Applicable Margin for Base Rate loans range from 0.75% to 2.00% based on our consolidated net total leverage ratio, and the Applicable Margin for LIBOR loans range from 1.75% to 3.00%, in each case based on our consolidated net total leverage ratio.
Series D Convertible Preferred Units
On March 28, 2014, we issued 1,818,182 Series D Preferred Units to Lonestar for $22.00 per Series D Preferred Unit for total consideration of $40.0 million in cash. The Series D Preferred Units are a new class of voting equity security that ranks senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. The Series D Preferred Units have voting rights identical to the voting rights of our common units and will vote with the common units as a single class. Each Series D Preferred Unit is entitled to one vote for each common unit into which such Series D Preferred Unit is convertible. We intend to redeem 100% of the issued and outstanding Series D Preferred Units prior to the consummation of this offering.
Cash Flow
Cash provided by (used in) operating activities, investing activities and financing activities were as follows for the periods indicated:
| |
Year Ended December 31, | Six Months Ended June 30, |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
2012 Restated and Recast |
|
|||||||||||||
| ($ in thousands) |
2011 | 2013 | 2013 | 2014 | ||||||||||||
Operating activities |
$ | (5,895 | ) | $ | (6,990 | ) | $ | 13,882 | $ | 24,778 | $ | 7,572 | ||||
Investing activities |
(26,860 | ) | (292,334 | ) | (27,735 | ) | (13,986 | ) | (4,936 | ) | ||||||
Financing activities |
34,825 | 304,991 | 6,988 | (11,482 | ) | (4,744 | ) | |||||||||
Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013
Cash provided by operating activities. Cash provided by operating activities was $7.6 million for the six months ended June 30, 2014 compared to $24.8 million for the six months ended June 30, 2013. The $17.2 million decrease was primarily attributable to a $11.8 million decrease in total Adjusted EBITDA, and a $4.5 million decrease due to the timing of collections and payments.
Cash used in investing activities. Cash used in investing activities was $4.9 million for the six months ended June 31, 2014 compared to $14.0 million for the six months ended June 30, 2013. The $9.1 million decrease was primarily due to an increase in proceeds from the sale of assets of $10.4 million, partially offset by a $1.7 million increase in capital expenditures in the six months ended June 30, 2014 associated with our various organic growth projects.
124
Cash used in financing activities. Cash used in financing activities was $4.7 million for the six months ended June 30, 2014 compared to $11.5 million for the six months ended June 30, 2013. The $6.8 million decrease was primarily due to a $48.0 million increase from the issuance of units, a $5.1 million increase from lower distributions to unitholders, and a $4.1 million increase in net borrowings under our revolving credit facility. These amounts are partially offset by the $52.0 million of cash used for the JP Development Dropdown in the six months ending June 30, 2014.
Cash flows from discontinued operations. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from these discontinued operations will have a significant impact to our future liquidity.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Cash provided by (used in) operating activities. Cash provided by operating activities was $13.9 million for the year ended December 31, 2013 compared to cash used in operating activities of $7.0 million for the year ended December 31, 2012. The $20.9 million increase was primarily attributable to seven acquisitions in 2012 that were completed in or after June, which provided a full year of cash generating operations in 2013 compared to a partial year of operations in 2012.
Cash used in investing activities. Cash used in investing activities was $27.7 million for the year ended December 31, 2013 compared to $292.3 million for the year ended December 31, 2012. The $264.6 million decrease was primarily due to an increase of $271.2 million of cash used for our 2012 acquisitions, partially offset by a $5.8 million increase in capital expenditures in 2013 associated with our various organic growth projects.
Cash provided by financing activities. Cash provided by financing activities was $7.0 million for the year ended December 31, 2013 compared to $305.0 million for the year ended December 31, 2012. The $298.0 million decrease was primarily due to a $147.0 million decrease from fewer units issued in 2013 compared to 2012 and a $119.8 million decrease in borrowings under our 2011 revolving credit facility. The decrease in both unit issuances and borrowings under the 2011 revolving credit facility are attributable to the decrease in acquisition activities in 2013 compared to 2012.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Cash used in operating activities. Cash used in operating activities was $7.0 million for the year ended December 31, 2012 compared to $5.9 million for the year ended December 31, 2011. The $1.1 million increase was primarily due to the timing of collections and payments.
Cash used in investing activities. Cash used in investing activities was $292.3 million for the year ended December 31, 2012 compared to $26.9 million for the year ended December 31, 2011. The $265.4 million increase was primarily due to an increase of $246.7 million of cash used for our acquisition activities in 2012. In addition, we had an $18.8 million increase in capital expenditures in 2012 associated with our various organic growth projects.
Cash provided by financing activities. Cash provided by financing activities was $305.0 million for the year ended December 31, 2012 compared to $34.8 million for the year ended December 31, 2011. The $270.2 million increase was due primarily to a $127.6 million increase in borrowings under our 2011 revolving credit facility and a $116.8 million increase from the issuance of units. The increase in both unit issuances and borrowings under our 2011 revolving credit facility are attributable to the increase in acquisition activities in 2012 compared to 2011.
125
Capital Expenditures
Our capital expenditures were $27.8 million, $293.3 million and $27.8 million for the years ended December 31, 2013, 2012 and 2011, respectively, which included capital expenditures for acquisitions of $1.0 million, $272.2 million and $25.5 million, respectively. While we refer to acquisitions made by JP Development of the assets that were subsequently acquired by us through the JP Development Dropdown as our acquisitions, we do not include capital expenditures made by JP Development to acquire those assets in the discussion of our capital expenditures.
Our capital spending program is focused on expanding our pipeline and cylinder exchange assets, maintaining our fleet and storage assets and maintaining and updating our information systems. Capital expenditure plans are generally evaluated based on return on investment and estimated incremental cash flow. In addition to annually recurring capital expenditures, potential acquisition opportunities are evaluated based on their anticipated return on invested capital, accretive impact to operating results and strategic fit.
Historically, we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Under our partnership agreement, maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will increase our operating income or operating capacity over the long-term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities.
We have budgeted $55.7 million in capital expenditures for the year ending December 31, 2014, of which $45.5 million represents expansion capital expenditures, which are expected to relate primarily to the expansion of our Silver Dollar Pipeline System and the expansion of our NGL cylinder exchange business and of which $10.2 million represents maintenance capital expenditures which we expect to spend primarily on fleet replacements and general maintenance. As of June 30, 2014 we have spent approximately $14.8 million of our $55.7 million in expected capital expenditures for the year ending December 31, 2014.
We anticipate that our capital expenditures will be funded primarily with cash from operations and borrowings under our revolving credit facility. Following this offering, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund any significant future expansion capital expenditures.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2013 is as follows:
| ($ in thousands) |
Less Than 1 Year |
2-3 Years | 4-5 Years | More Than 5 Years |
Total | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Long-term debt obligations(1) |
$ | 698 | $ | 1,730 | $ | 726 | $ | 181,692 | $ | 184,846 | ||||||
Capital lease obligations(2) |
178 | 242 | 84 | 51 | 555 | |||||||||||
Operating lease obligations(2) |
6,174 | 11,685 | 4,688 | 5,497 | 28,044 | |||||||||||
Total |
$ | 7,050 | $ | 13,657 | $ | 5,498 | $ | 187,240 | $ | 213,445 | ||||||
- (1)
- Does not reflect that upon the closing of this offering we expect to (i) repay approximately $195.6 million of the debt outstanding under our revolving credit facility and (ii) incur long-term debt under our revolving credit facility of approximately $75.0 million, which will be used to replenish working capital as described in "Use of Proceeds."
126
- (2)
- Represents future minimum lease payments under non-cancelable operating and capital leases related to various buildings, land, storage facilities, transportation vehicles and office equipment. See note 11 and note 16 to our consolidated financial statements included elsewhere in this prospectus.
Off Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual arrangements that would result in off balance sheet liabilities, except for operating lease commitments as disclosed in the contractual obligations table above.
Working Capital
Our working capital is the amount by which our current assets exceed our current liabilities and is a measure of our ability to pay our liabilities as they come due. Our working capital was $43.0 million, $48.7 million and $37.0 million as of June 30, 2014, December 31, 2013 and December 31, 2012, respectively.
The $5.7 million decrease in working capital from December 31, 2013 to June 30, 2014 was primarily the result of the following factors:
- •
- a $28.4 million increase in accounts payable and accrued liabilities due primarily to the timing of payments;
- •
- a $18.2 million decrease in inventory due to the timing of inventory purchases and sales in our crude oil supply
and logistics business; offset by
- •
- a $39.3 million increase in accounts receivable primarily due to the timing of collections; and
- •
- a $3.2 million increase in prepaid expenses and other current assets due primarily to a $2.8 million increase in prepaid business insurance premiums from the renewal of our policy.
The $11.7 million increase in working capital from December 31, 2012 to December 31, 2013 was primarily a result of the following factors:
- •
- a $42.4 million increase in accounts receivable primarily due to an increase in revenue;
- •
- a $18.9 million increase in inventory due primarily to a $15.5 million increase from the timing of inventory
purchases and sales in our crude oil supply and logistics business and a $1.7 million increase from acquisitions during the year ended December 31, 2013; offset by
- •
- a $45.5 million increase in accounts payable and accrued liabilities due primarily to a $26.2 million increase from acquisitions during the year ended December 31, 2013, a $14.0 million increase in accounts payable due to the timing of payments and a $4.5 million increase in accrued payroll and employee benefits as a result of an increase in employee headcount.
Our working capital requirements have been and will continue to be primarily driven by changes in accounts receivable and accounts payable, which generally fluctuate with changes in the market prices of commodities that we buy and sell in the ordinary course of our business. Other factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as our level of spending for maintenance and growth capital expenditures. A material adverse change in our operations or available financing under our
127
revolving credit facility could impact our ability to fund our working capital requirements for liquidity and capital resources.
Qualitative and Quantitative Disclosures About Market Risk
Commodity price risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
We do not have direct exposure to commodity price changes in our crude oil pipelines and storage segment. In our crude oil supply and logistics business, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using financial swaps. In our cylinder exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a large majority of the forecasted volumes under our long-term contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. In our NGL transportation business, we do not take title to the products we transport and, therefore, have no direct commodity price exposure to the price of volumes transported.
Sensitivity analysis. We have prepared a sensitivity analysis to estimate the exposure to market risk of our propane commodity positions. Forward contracts outstanding as of December 31, 2012 and December 31, 2013 that were used in our risk management activities were analyzed assuming a hypothetical 10% adverse change in prices for the delivery month for propane. The potential loss in earnings from these positions due to a 10% adverse movement in market prices of propane was estimated at $0.8 million, $0.2 million and $0.8 million as of June 30, 2014, December 31, 2013 and December 31, 2012, respectively. The preceding hypothetical analysis is limited because changes in prices may or may not equal 10% and actual results may differ.
Interest rate risk. Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable interest rates. At present, $75 million of our outstanding debt is economically hedged with interest rate swaps over three years with a weighted average interest rate of 0.48% plus an applicable margin. A hypothetical increase or decrease in interest rates of 1.0% would have increased or decreased, respectively, our interest expense by $1.1 million for the six months ended June 30, 2014 by $1.0 million for the year ended December 31, 2013 and $0.8 million for the year ended December 31, 2012.
We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.
128
Internal Controls and Procedures
Prior to the completion of this offering, we have been a private entity with limited accounting personnel and other supervisory resources to adequately execute our accounting processes and address our internal control over financial reporting. In connection with the audits of our financial statements for the years ended December 31, 2011, 2012 and 2013, our independent registered public accounting firm identified material weaknesses in internal control over financial reporting relating to (i) accounting resources and policies (including maintaining an effective control environment), (ii) accounting for business combinations and (iii) information technology.
A "material weakness" is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We did not have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements. As a result, we did not design and maintain formal accounting policies and formal review controls. We did not design and maintain effective controls over accounting for business combinations, including controls related to the valuation of assets acquired and liabilities assumed, and the integration of businesses by applying consistent accounting policies and processes to determine compliance with industry standards and regulations. We did not design and maintain adequate policies and procedures with respect to the primary components of information technology general controls, including the approval and review of access controls, system implementation and migration controls, and change management controls. These material weaknesses resulted in audit adjustments in the years ended December 31, 2011, 2012 and 2013 and the three months ended March 31, 2012 and 2013 and six months ended June 30, 2013, and restatements of our financial statements for the years ended December 31, 2011, 2012 and the three months ended March 31, 2012 and 2013. Management has determined that the excessive product gains at a refined products terminal described in Note 10 to the consolidated financial statements for the six months ended June 30, 2014 was an additional effect of the material weakness related to business combinations and information technology described above. Also, management has determined that the excessive product gains at a refined products terminal relate to not designing and maintaining effective controls to determine compliance with industry standards and regulations during the integration of the acquired business. As a result, the description of the business combination material weakness at June 30, 2014 was expanded to include this aspect of the material weakness related to integration of acquired businesses.
While we have begun the process of implementing additional processes and controls related to accounting and financial reporting, we will not complete our implementation until after this offering is completed. During the course of the implementation, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above or any newly identified material weakness could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected.
We are not currently required to comply with the SEC's rules implementing Section 404 of Sarbanes Oxley, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC's rules implementing Sections 302 and 404 of Sarbanes Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Although we will be required to disclose changes made to our internal control over financial reporting and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of Sarbanes Oxley and our independent registered public accounting firm will not be required to issue an
129
attestation report on the effectiveness of our internal control over financial reporting until the fiscal year ending December 31, 2015. In order to have effective control over financial reporting, we will need to implement additional internal controls, reporting systems and procedures.
Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal control over financial reporting, and we may incur significant costs in our efforts to comply with Section 404 of Sarbanes Oxley. Any failure to implement and maintain effective internal control over financial reporting will subject us to regulatory scrutiny and could result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Critical Accounting Policies and Estimates
Our significant accounting policies are described in note 2 to our audited consolidated financial statements included elsewhere in this prospectus. We prepare our consolidated financial statements in conformity with GAAP, and in the process of applying these principles, we must make judgments, assumptions and estimates based on the best available information at the time. To aid a reader's understanding, management has identified our critical accounting policies. These policies are considered critical because they are both most important to the portrayal of our financial condition and results, and require our most difficult, subjective or complex judgments. Often they require judgments and estimation about matters which are inherently uncertain and involve measuring, at a specific point in time, events which are continuous in nature. Actual results may differ based on the accuracy of the information utilized and subsequent events, some over which we may have little or no control.
Revenue Recognition
We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller's price to the buyer is fixed and determinable and collectability is reasonably assured. Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, are presented on a net basis within the consolidated statements of operations.
Crude oil pipelines and storage. We generate revenue through crude oil sales and pipeline transportation and storage fees. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, we enter into sale and purchase contracts with counterparties that are the equivalent of pipeline transportation agreements. In such cases, we assess the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. Revenues from crude oil storage services are recognized when services are provided.
Crude oil supply and logistics. We generate revenue mainly through crude oil sales. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contract we gather, transport and blend different types of crude oil and eventually sell the blended crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty in the way that the buy and sell of inventory are in contemplation with each other. Revenue from such inventory exchange arrangements are recorded on a net basis. In addition, we also provide crude oil transportation services to third party customers. Revenue from these transportation services are recognized when the service is provided and when payment has either been received or collection is reasonably assured.
130
Refined products terminals and storage. We generate fee-based revenues with customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes. Revenues from refined products are recognized as products stored or delivered by us when we provide services with respect to or deliver such products, as applicable.
NGLs distribution and sales. Revenues from our NGL distribution and sales segment are mainly generated from NGL and refined product sales, sales of the related parts and equipment and gathering and transportation fees that are recognized in the period that the products are delivered and when payment has either been received or collection is reasonably assured
Impairment of Long-Lived Assets
Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary.
Goodwill and Intangible Assets
We apply Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill and intangible assets. In accordance with these standards, we amortize all definite-lived intangible assets over their respective estimated useful lives, while goodwill has an indefinite life and is not amortized. We review finite-lived intangible assets subject to amortization for impairment whenever events or circumstances indicate that the associated carrying amount may not be recoverable.
We have recorded goodwill in connection with our historical acquisitions. Upon acquisition, these companies have been either combined into one of our existing operating units or managed on a stand-alone basis as an individual operating unit. Goodwill recorded in connection with these acquisitions is subject to an annual assessment for impairment, which we perform at the operating unit level for each operating unit that carries a balance of goodwill. Each of our operating units is organized into one of four business segments: Crude Oil Pipelines and Storage, Crude Oil Supply and Logistics, Refined Products Terminals and Storage, and NGL Distribution and Sales. Goodwill is required to be measured for impairment at the operating segment level or one level below the operating segment level for which discrete financial information is available, and we have determined following reporting units for the purpose of assessing goodwill impairments.
| Operating Segments | Reporting Units | |
|---|---|---|
| Crude Oil Pipelines and Storage | JP Permian | |
| JPE Storage | ||
| Crude Oil Supply and Logistics | JPE Product Supply and Logistics | |
| Refined Product Terminals and Storage | ATT and Caddo Mills | |
| NGL Distribution and Sales | Pinnacle Propane | |
| Pinnacle Propane Express | ||
| JP Liquids |
131
Our goodwill impairment assessment is performed at year-end, or more frequently if events or circumstances arise which indicate that goodwill may be impaired.
We have the option to first assess qualitative factors to determine whether it is necessary to perform the two-step fair value-based impairment test described below. We can choose to perform the qualitative assessment on none, some or all of our reporting units. We can also bypass the qualitative assessment for any reporting unit in any period and proceed directly to step one of the impairment test, and then resume performing the qualitative assessment in any subsequent period. Qualitative indicators including deterioration in macroeconomic conditions, declining financial performance that, among other things, may trigger the need for annual or interim impairment testing of goodwill associated with one or all of the reporting units. If we believe that, as a result of our qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. The first step of the two-step fair value-based test involves comparing the fair value of each of our reporting units with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the reporting unit's goodwill to the implied fair value of its goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss would be recorded as a reduction to goodwill with a corresponding charge to operating expense.
We determine the fair value of our reporting units using a weighted combination of the discounted cash flow and market multiple valuation approaches, with heavier weighting on the discounted cash flow method, as in management's opinion, this method currently results in the most accurate calculation of a reporting unit's fair value. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, discount rates, weighted average costs of capital and future market conditions, among others. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.
Under the discounted cash flow method, we determine fair value based on the estimated future cash flows of each reporting unit (including estimates for capital expenditures), discounted to present value using risk-adjusted industry discount rates, which reflect the overall level of inherent risk of a reporting unit and the rate of return an outside investor would expect to earn. Cash flow projections are derived from budgeted amounts and operating forecasts (typically a one-year model) plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur, along with a terminal value derived from the reporting unit's earnings before interest, taxes, depreciation and amortization, as well as other non-cash items or one-time non-recurring items (Adjusted EBITDA) using the Gordon Growth Model.
Under the market multiple approach, we determine the estimated fair value of each of our reporting units by applying transaction multiples derived from observable market data to each reporting unit's projected Adjusted EBITDA and then averaging that estimate with similar historical calculations using either a one, two or three year average. We add a reasonable control premium, which is estimated as the premium that would be received in a sale of the reporting unit in an orderly transaction between market participants.
During the second quarter of 2014, due to the actual operating results for the six months period ended June 30, 2014 being significantly below management's budget for certain reporting units, a two-step fair-value based goodwill impairment analysis was performed for five of the seven of our reporting units, namely JP Permian, JPE Product Supply and Logistics, Pinnacle Propane, Pinnacle Propane Express, and JP Liquids. Management engaged a third party valuation expert to assist performing the analysis using the valuation approaches described in the preceding paragraphs. The analysis indicated
132
that the implied fair value of each of these reporting units was in excess of its carrying value. Based on the analysis, management concluded that no impairment was indicated at any reporting unit.
No impairment charge for goodwill or other intangible assets was recorded during 2011, 2012 or 2013. During the second quarter of 2014, immediately prior to the sale of the Bakken Business within our JPE Product Supply and Logistics reporting unit, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit we retained. The $1,984,000 allocation contributed to the overall net loss from discontinued operations. For further discussion of goodwill and intangible assets, see note 9 to our consolidated financial statements and note 6 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus.
Risk Management Activities and Derivative Financial Instruments
We have established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The board of directors of our general partner is responsible for the overall management of these risks, including monitoring exposure limits. We do not enter into derivative instruments for any purpose other than economic commodity pricing and interest rate hedging. We enter into commodity forward and swap contracts to hedge exposures to market fluctuations in propane prices and interest rate swap contracts to hedge exposures to variable interest rate risk. These derivative contracts are reported in our consolidated balance sheets at fair value with changes in fair value recognized in cost of sales, excluding depreciation and amortization, and interest expense in our consolidated statements of operations. We estimate the fair value of our derivative contracts using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves. Changes in the methods used to determine the fair value of these contracts could have a material effect on our consolidated balance sheets and consolidated statements of operations. For further discussion of derivative contracts, see note 13 to our consolidated financial statements included elsewhere in this prospectus. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.
Business Combinations
When a business is acquired, we allocate the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. ASC 805, Business Combinations, requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs incurred for the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt's stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite.
When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting. In a common control acquisition, the assets and liabilities are recorded at the transferring entity's historical cost instead of reflecting the fair market value of assets and liabilities.
Equity-Based Compensation
ASC 718, Stock Compensation, requires all share-based payments to employees to be recognized in the financial statements, based on the fair value on the grant date, date of modification or end of the period, as applicable, and recognized in earnings over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as equity in the consolidated balance sheets. Equity-based compensation costs associated with the portion of awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. We estimate the fair value of our common units by dividing the estimated total enterprise value by the number of outstanding units. Estimated total enterprise value was determined using the income approach of discounting the estimated future cash flow to its present value. We also estimated a 10% forfeiture rate in calculating the unit-based compensation expense.
133
Our operations consist of (i) crude oil pipelines and storage services provided to producers and marketers, (ii) crude oil supply and logistics services provided to producers, aggregators, traders and refiners, (iii) refined products terminals and storage services provided to large oil companies and refiners and (iv) NGL distribution and sales through our cylinder exchange business, our NGL sales business and our NGL transportation business. Our affiliate, JP Development, provides crude oil pipeline transportation services.
The following diagram depicts the segments of the crude oil and refined products value chain as well as our participation in the crude oil and refined products industry:
The services we and other companies with similar operations provide are generally classified into the categories we describe in this "Industry" section. As indicated above, we do not currently provide all of these services, although we may do so in the future.
Crude oil pricing is generally quoted in reference to the classification of the crude, which is based on certain physical characteristics, the source of its production and the major trading hub with which it is associated. Relevant classifications of crude oil include:
- •
- West Texas Intermediate (WTI). WTI is a grade of crude oil
that is described as light because of its relatively low density, and sweet because of its low sulfur content. Cushing, Oklahoma is a major trading hub for WTI and has been the delivery point for
crude contracts, and therefore the price settlement point, on the New York Mercantile Exchange (NYMEX) for over three decades.
- •
- Louisiana Light Sweet (LLS). LLS is a major benchmark for
sweet light crude oil that is sourced from the Gulf Coast region. It has a slightly higher density and slightly lower sulfur content than WTI.
- •
- Brent crude oil (Brent). Brent is a major trading classification of sweet light crude comprised of Brent, Forties and Oseberg and Ekofisk, which are types of crude blends sourced from the North Sea. The Intercontinental Exchange (ICE) is a major trading hub for Brent crude. Petroleum suppliers in Europe, Africa and the Middle East often set prices for Brent crude according to its value on the ICE if it is being sold in the West.
134
Over the last five years, benchmark WTI crude oil has increased by approximately 58%, rising from an average of $62 per barrel in 2009 to an average of $98 per barrel in 2013.
The crude oil and refined product market within the United States is divided geographically into five Petroleum Administration for Defense Districts ("PADDs"). The map below shows the movement of crude oil as well as petroleum products between PADDs in 2013.
2013 Aggregate Crude Oil and Petroleum Products Movements Between PAD Districts (Mbbls)
Source: Energy Information Administration—Movements Between PAD Districts
Due to advances in unconventional drilling technology and improved drilling economics, crude oil production in the United States increased by 39%, from approximately 5,350 Mbbls per day in 2009 to almost 7,450 Mbbls per day in 2013, with the Midwest and Rockies (PADDs 2 and 4) regions representing 26% of 2013 production, according to the Energy Information Administration (the "EIA"). NGL production in the United States has followed a similarly strong growth trajectory, increasing 34% from approximately 1,900 Mbbls per day in 2009 to approximately 2,550 Mbbls per day in 2013, with the Midwest and Rockies regions representing 31% of 2013 production. Growing crude oil production in the land-locked interior of North America has resulted in crude oil prices in these regions generally being lower than prices on the Gulf Coast, where domestic and imported crude oil has traditionally been delivered. Because of this new supply dynamic, price differentials now provide a strong incentive for increasing crude oil movements out of the Midwest, even using alternative modes of transportation such as rail and trucks. By way of example, crude volumes transported via pipeline from the Midwest (PADD 2) to the Gulf Coast (PADD 3) have risen from 52 Mbbls per day in 2009 to 367 Mbbls per day in 2013. In addition, with access to lower cost crude oil supplies, inland refineries have experienced attractive economics producing competitively priced refined petroleum products relative to the Gulf Coast and other regions in the United States. This has resulted in a significant decrease in the flow of crude oil from the Gulf Coast to the Midwest and significantly more flow of refined petroleum products from the Midwest to the Gulf Coast. For example, the flow of crude oil from the Gulf Coast to the Midwest decreased from 1,177 Mbbls per day in 2009 to 908 Mbbls per day in 2013, and the flow of petroleum products from the Midwest to the Gulf Coast rose from 332 Mbbls per day in 2009 to 422 Mbbls per day in 2013.
The following table shows the historical price differentials among WTI, LLS and Brent. LLS and Brent have traded at a premium to WTI, which serves as a proxy for crude oil sourced from the
135
Mid-Continent region, over the last few years. The differential between WTI and LLS averaged $9.42 in 2013. The differential between WTI and Brent averaged $10.82 in 2013. As of April 2014, the EIA expects the differential between WTI and Brent to average $9.00 in 2014 and $11.00 in 2015.
Recent refinery dynamics reflect shifts in crude production. To take advantage of increased production, overall refinery utilization in the United States rose from 82.9% in 2009 to 88.3% in 2013. Refining activity has increased in areas where we currently have operations. Midwest (PADD 2) refinery crude input increased approximately 9% from 3,135 Mbbls per day in 2009 to 3,406 Mbbls per day in 2013. Similarly, Gulf Coast (PADD 3) refinery crude input increased approximately 13% from 7,020 Mbbls per day in 2009 to 7,953 Mbbls per day in 2013.
We are positioned to serve numerous areas primarily in Texas and Oklahoma (PADDs 2 and 3). A few of the key hydrocarbon-producing areas that we are strategically located to serve include the Permian Basin, Niobrara shale, Eagle Ford shale, Granite Wash play and Mississippian Lime play.
- •
- Permian Basin. The Permian Basin, located in West Texas
and Southeastern New Mexico, occupies approximately 86,000 square miles. It is generally characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon
potential in multiple intervals and also includes emerging areas such as the Wolfcamp, Cline, Spraberry, Wolfberry Bone Spring, Yeso and Avalon plays. According to Wood Mackenzie, an energy industry
research and consulting firm, production in the Permian Basin grew by 13% in 2013, with 88% of the production growth coming from crude oil. Including production from conventional drilling, the Permian
Basin contributed approximately 18% of total crude production in the United States in 2013. Total spending in this area grew at a faster rate, increasing 23% over 2012 levels to a total of
$25 billion in 2013. The economics of this basin generally remain favorable even in low oil price environments. Wood Mackenzie estimates production to reach 3,000 Mboe per day by 2017.
- •
- Wolfcamp shale. The Wolfcamp formation is an oil-rich carbonate and shale play in the Midland Basin within the Permian, spanning approximately 5,100 square miles. It is
136
- •
- Niobrara shale. The Niobrara shale is located primarily
within the Rocky Mountain region and covers approximately 5,100 square miles across Colorado, Wyoming, Nebraska, Kansas and New Mexico. In recent years, operators have targeted the Niobrara shale for
oil production in and around the Wattenberg field and the Colorado Mineral belt to the Northeast. Crude oil and condensate production grew from approximately 35 Mbbls per day in 2011 to
approximately 110 Mbbls per day in 2013. Wood Mackenzie expects that production will reach approximately 390 Mbbls per day by 2017. The typical well life across the oil and gas plays in
the Niobrara is approximately 30 years.
- •
- Eagle Ford shale. According to Wood Mackenzie, the Eagle
Ford shale region spans 14 counties in South Texas and covers over 11,000 square miles. It is characterized by having three distinct "windows," the oil, condensate and gas windows. Wood
Mackenzie reports production in the Eagle Ford shale region has grown rapidly, from approximately 5 MBoe per day in 2009 to approximately 1,406 MBoe per day in 2013. In 2013, Wood
Mackenzie reported that the Eagle Ford shale region was responsible for approximately 12% of crude production in the United States. In 2014, Wood Mackenzie expects $27 billion to be spent in
the Eagle Ford shale region. Wood Mackenzie expects that production will reach 2,226 MBoe per day by 2017. The horizontal wells in this region have expected production lives averaging
approximately 25 years across all three windows.
- •
- Granite Wash play. The Granite Wash play spans 4,765
square miles and is located primarily in western Oklahoma and the northeastern Texas Panhandle. Tight gas has been harnessed in the region for decades, but horizontal drilling has rejuvenated the play
and is the source of projected growth. Because the play is predominately NGL-rich gas, Wood Mackenzie reported production increased by 10% from approximately 1,596 MMcfe per day in
2011 to approximately 1,750 MMcfe per day 2013. Wood Mackenzie expects that production will reach approximately 2,100 MMcfe per day by 2017. The horizontal wells in this play have
expected production lives averaging approximately 25 years.
- •
- Mississippian Lime play. The Mississippian Lime play, which underlies the Anadarko Basin, is located primarily within the Mid-Continent area and covers approximately 36,000 square miles across northern Oklahoma and southern and western Kansas. Although operators have drilled the area with vertical wells for several decades, projected growth is expected to be driven predominately by advances in horizontal drilling. Although the play is still in early stages of development, Wood Mackenzie reported production increasing significantly from approximately 61 MBoe per day in 2011 to approximately 180 MBoe per day in 2013. Wood Mackenzie expects that production will reach 325 MBoe per day by 2017. While the wells in this play produce large volumes of salt water, the economics and lives of wells are still favorable, with the typical well producing oil and gas for over 20 years.
expected to drive much of the production growth in the Permian with over 18,000 potential well locations. Drilling activity in the main area of the Wolfcamp shale has increased rapidly with rig count growing from three in 2009 to over 50 in April 2013. Production has grown significantly from 11 MBoe per day in 2011 to approximately 110 MBoe per day in 2013, according to Wood Mackenzie. Wood Mackenzie expects that production will reach approximately 650 MBoe per day in 2017. Wells in the Wolfcamp formation have an expected life of 30 years.
Crude Oil Industry Value Chain
Gathering and Transportation
Crude oil gathering and transportation assets are integral to the crude oil value chain and transport oil from the wellhead to logistics hubs and/or refineries. Logistic hubs, such as the hub
137
located in Cushing, Oklahoma, provide storage and connections to other pipeline systems and modes of transportation, such as tank barges, railroads and trucks. We provide many of the services within this portion of the crude oil value chain.
Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the United States. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Long-haul crude oil pipelines serve producer and refiner customers by addressing regional crude oil supply and demand imbalances. This type of pipeline primarily consists of large diameter, high pressure steel pipeline up to hundreds of miles in length with ancillary assets which could include terminals, receipt points, pump stations and storage facilities.
Crude oil gathering assets generally consist of a network of smaller diameter pipelines that are connected directly to the well site or central receipt points delivering into larger diameter trunk lines. Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation.
Barges and railroads are also utilized for shipping crude oil to refiners and marketers.
Competition in the crude oil gathering and transportation industry is typically regional and based on the proximity of the crude oil gathering and transportation assets to crude oil producers, as well as access to attractive delivery points.
Storage Terminals, Supply and Logistics
Crude oil storage terminals are typically located at marketing and logistics hubs where crude oil is transferred across pipelines, trucks, railroads or barges. Customers typically pay a fee known as a firm reservation fee for storage capacity at crude oil storage terminals regardless of their usage of the reserved capacity. Storage terminals complement crude oil pipeline gathering and transportation systems and address a fundamental imbalance in the energy industry, which is that crude oil is produced in different locations and at different times than it is ultimately consumed.
We complement our crude oil supply and logistics business by utilizing trucks as a method to transport crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Higher growth basins, such as those where we operate, often lack pipeline infrastructure when the production economics or well locations do not justify the capital costs. Emerging resource plays, such as areas of the Permian Basin, Niobrara shale, Eagle Ford shale, Granite Wash play and Mississippian Lime play are well-suited for trucking due to the limited upfront capital costs of trucks and the flexibility to redeploy them if economic conditions change. Trucking is generally limited to short-haul movements because transportation costs generally escalate with distance. Importantly, our trucking assets enable us to build strong relationships with producers, which potentially contributes to the origination of growth opportunities.
Overview of the Cushing Interchange
Cushing, Oklahoma is the largest crude oil operational and marketing hub in the United States. The city rose to prominence as a regional oil production and refining center. Today, it serves as an interconnection point for numerous inbound pipelines and as a significant crude oil storage hub for Mid-Continent and Gulf Coast refiners. Cushing is the most liquid point in the United States for delivery of crude oil sold on the NYMEX.
Storage capacity at Cushing, while relatively constant through the 1990s and early 2000s, began to increase significantly in the mid-2000s. This growth in capacity was a direct result of the strong economics associated with crude oil storage. According to the EIA, Cushing shell storage and working
138
capacity were 77.3 million barrels and 65.7 million barrels, respectively, in September 2013. At any given time, Cushing holds 4% to 14% of the total crude oil inventory of the United States. Cushing crude oil stocks have built from approximately 35,600 Mbbls at year-end 2009 to approximately 41,400 Mbbls at year-end 2013.
With recent increases in unconventional crude oil production, Cushing has begun to play an even larger role in aggregating volumes for further transportation and delivery to end-users. It is located at a key crossroad connecting the Bakken shale, unconventional Mid-Continent plays and Canadian production to the Gulf Coast. According to the EIA, inbound crude pipeline capacity into Cushing has risen rapidly, growing by 815 Mbbls per day from 2010 to 2012. However, recent pipeline capacity expansions and pipeline reversals, such as the reversal in May 2013 by Enterprise Product Partners and Enbridge of the Seaway Pipeline, have helped alleviate transportation bottlenecks at Cushing.
Refined Products Industry Overview
Refined petroleum products are energy sources derived from crude oil that have been processed through various refining methods. The resulting products include gasoline, home heating oil, jet fuel, diesel, lubricants and the raw materials for fertilizer, chemicals and pharmaceuticals. According to data compiled by the EIA, liquid fuels and other petroleum products accounted for 37.8% of the nation's total annual energy consumption in 2012. With respect to terminal storage of petroleum products, volumes have increased 37.6% from 2000 to 2013 according to the EIA.
The United States refined products distribution system moves petroleum products and by-products from oil refineries to end users. This distribution system is comprised of a network of terminals, storage facilities, pipelines, barges, railroads and trucks. Terminals are integral to the distribution of refined products and are facilities where products are transferred to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks. Terminals play a key role in moving product to the end-user market by providing the following services:
- •
- receipt, storage, inventory management and re-delivery;
- •
- blending to achieve specified grades of gasoline; and
- •
- other ancillary services that include additive injection per regulatory or customer specifications and jet fuel handling, including filtration.
At the terminals, the various refined petroleum products are segregated and stored in tanks. Typically, refined products terminals are equipped with automated truck loading facilities commonly referred to as "truck racks" that operate 24 hours a day. Truck racks provide for control of security, allocations, credit and carrier certification by remote data input. Trucks pick up refined products at the truck racks and transport them to commercial, industrial and retail end-users. Additionally, some terminals use railcars or barges to deliver refined products from and receive refined products into the terminal.
During the loading process, additives such as butane and ethanol may be introduced into refined products by computer-controlled injection systems that enable the refined products being loaded to conform to governmental regulations and individual customer requirements. For example, less expensive butane is blended into higher priced gasoline to generate additional profits while complying with regional and seasonally variable specifications for maximum vapor pressure. Similarly, ethanol is blended into gasoline to generate additional profits as well as improve environmental impact.
Competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms. Competition in particular geographic areas is affected primarily by the volumes of refined
139
products produced by refineries located in those areas and by the availability of refined products and the cost of transportation to those areas from refineries located in other areas.
NGLs are valuable hydrocarbons with energy density between that of natural gas and crude oil. NGLs occur in some natural gas streams and can be produced by refineries. Capital-intensive processing and fractionation processes are necessary to separate NGLs into purity products suitable for petrochemical, industrial and residential end-users.
The principal component products of the NGLs stream and their primary uses are as follows:
- •
- Ethane. Ethane is used primarily as feedstock in the
production of ethylene, one of the basic building blocks for a wide range of plastics and other chemicals.
- •
- Propane. Propane is used as a heating fuel, engine fuel
and industrial fuel, for agricultural drying, in oilfield service applications and as petrochemical feedstock for production of ethylene and propylene.
- •
- Butane. Normal butane is principally used for motor
gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also
used to derive isobutane.
- •
- Isobutane. Isobutane is principally used by refiners to
enhance the octane content of motor gasoline and in the production of methyl tertbutyl ether, an additive in cleaner burning motor gasoline.
- •
- Natural gasoline. Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.
Shale drilling has led to increased production of natural gas rich in NGLs. Our NGL distribution and sales segment serves as an important outlet for increased domestic NGL supply, providing us with an opportunity to negotiate pricing discounts as a large purchaser. The recent decline in NGL prices relative to crude-based product prices may positively impact NGL demand and thereby contribute to future sales volumes. According to the EIA, total NGL consumption in the United States increased from approximately 2,700 MMgal per month in 2009 to over 3,100 MMgal per month in 2013.
Propane Overview
Propane is a clean-burning energy source recognized for its transportability and ease of use relative to alternative stand-alone energy sources. Propane competes primarily with natural gas, electricity and fuel oil as an energy source principally on the basis of price, availability and portability. According to the EIA, propane consumption in our core Gulf Coast (PADD 3) footprint grew from approximately 663 MMgal per month in 2008 to more than 775 MMgal per month in 2013.
The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. The retail propane industry is relatively mature and overall demand for propane is not expected to grow. However, the propane distribution industry is undergoing consolidation as large distributors with a national presence are gaining market share. Many small independent distributors are selling their companies rather than face escalating capital requirements needed to replace fleet vehicles and acquire advanced, customer-oriented technologies used for routing, delivery forecasting and remote tank monitoring.
140
The following diagram illustrates the various components of the propane distribution and sales industry:
Propane Demand
Demand for propane as a fuel in oilfield service and agricultural applications has increased due to growing supply and resulting lower prices. International demand for NGLs has provided an outlet for growing domestic production, and after years of being a net importer, the United States became a net exporter of propane in 2012 according to the EIA.
Propane is consumed by the following end-users:
- •
- Agricultural. Agricultural customers use propane primarily
for crop drying, tobacco curing, poultry brooding, heating livestock buildings, weed control, farm equipment and irrigation pumps. Agricultural use of propane is primarily concentrated in the Midwest
and demand can vary year to year depending on crop size and moisture content.
- •
- Oil and gas industry. The oil and gas industry uses
propane primarily as fuel for oilfield service equipment such as generators, pressure pumping equipment and completion equipment. Propane serves as an alternative to other fuels that are unavailable
or uneconomical to procure in remote locations near the wellhead. The use of propane for oilfield service applications is not usually seasonal because United States oil and gas companies typically
operate throughout the year.
- •
- Residential. Residential customers use propane primarily
for outdoor cooking, space heating, water heating and operating propane-fueled appliances. Because many residential propane customers rely on propane as their primary heating fuel, residential propane
usage is seasonal with the highest demand in the fall and winter months. However, this seasonality is offset by the heavy use of propane cylinders for outdoor cooking during the spring and summer
months.
- •
- Commercial and industrial. Commercial customers, such as
restaurants, motels, laundries and commercial buildings, use propane in a variety of applications, including cooking, heating and drying. Industrial customers use propane primarily as engine fuel for
forklifts and stationary engines, to fire furnaces, in mining operations and in other industrial applications. Propane usage by commercial and industrial customers is typically not seasonal.
- •
- Petrochemical industry. The petrochemical industry uses propane as a raw material to make products such as plastic and nylon. Propane usage by the petrochemical industry tends to rise
141
during the summer when the price of propane is generally lower and tends to fall during the winter heating months when the price of propane is generally higher. Petrochemical demand for propane is also regional due to the high concentration of petrochemical plants in the Gulf Coast region.
Cylinder Exchange
Propane cylinders are typically used in residences for outdoor cooking, space heating, water heating and operating propane-fueled appliances. Companies that operate propane cylinder exchange businesses source propane from bulk propane storage facilities generally located near major NGL production, processing and transportation hubs. Liquefied petroleum gas (LPG) transport trucks, with capacities ranging from 9,000 to 10,600 gallons, deliver propane from suppliers to production facilities where cylinders are processed and filled. Filled cylinders are loaded onto relay trucks that deliver the cylinders to the customer's retail site which include grocery stores, pharmacies, convenience stores and hardware retailers. The cylinders hold 3.5 gallons and are typically 20-lbs. steel containers to which customer-specific materials and branding can be affixed.
Barriers to entry for the propane cylinder exchange market are higher than other propane-oriented businesses due to requirements for automated production plants and logistics. Each used cylinder must be transported to a processing facility, cleaned, rebranded and placed back into circulation between each use. In addition, propane cylinder exchange distributors that have a national presence like us have more opportunities to provide propane to large volume retailers that operate on a nationwide basis such as big box, hardware, grocery, convenience and drug store chains.
While some propane cylinder customers use propane as heating fuel during the fall and winter months, most of the demand for propane cylinder exchange is in the spring and summer months for non-heating related purposes such as outdoor cooking. Home barbecue grilling has increased rapidly since the mid-1990s: 82% of households have an outdoor grill and 60% of such grills are powered by NGLs. NGL volumes attributable to barbecue grilling approximate 500 million gallons per year. This summer-weighted seasonality offsets heating related demand for propane during the colder parts of the year.
NGL Distribution
NGLs including propane, butane and natural gasoline are transported from bulk storage facilities generally located near major NGL production, processing and transportation hubs to commercial or industrial end-users often using hard shell tank trucks.
Propane for wholesale and retail distribution is sourced from bulk propane storage facilities generally located near major NGL production, processing and transportation hubs. Wholesale and retail end-users typically have small above-ground tanks that have propane storage capacity located mostly at the point of consumption at residences, commercial establishments and other end-user locations.
Typically, LPG transport trucks pick up propane at supply points and transport propane directly to wholesale customers such as commercial, industrial and governmental end-users. Generally, wholesale customer sites consist of 2,500 to 45,000 gallon storage tanks on the premises.
Retail deliveries of propane are usually made to customers by means of bobtail trucks. Propane is pumped into bobtail trucks, which have capacities ranging from 2,200 to 5,000 gallons. In turn, the trucks deliver propane to stationary storage tanks on customers' premises. The capacity of these storage tanks ranges from approximately 120 to 12,000 gallons, with a typical tank having a capacity of 250 to 500 gallons. Residential customers can also bring their own cylinders to customer service distribution locations to be refilled.
142
We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized in June 2011 by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of four business segments: (i) crude oil pipelines and storage, (ii) crude oil supply and logistics, (iii) refined products terminals and storage and (iv) NGL distribution and sales. Together our businesses provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:
- •
- owning, operating and developing midstream assets serving areas experiencing dramatic increases in drilling activity and
production growth, as well as serving key crude oil, refined product and NGL distribution hubs;
- •
- providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing
product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and
- •
- operating one of the largest portable propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.
We intend to continue to expand our business by acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs. Our crude oil businesses are situated in high growth areas, including the Permian Basin, Mid-Continent and Eagle Ford shale, and provide us with a footprint to increase our volumes as these areas experience further drilling and production growth. In addition, we believe we have a competitive advantage with regard to the sourcing of opportunities to build, own and operate additional crude oil pipelines due to the insights in the market that we obtain while providing services to customers in our crude oil supply and logistics segment. We believe that our NGL distribution and sales segment will continue to grow due to our recent expansion into new geographic markets, an increased market presence in our existing areas of operation and the increase in industrial and commercial applications for NGLs such as in oilfield and agricultural services.
Since our formation and the formation of our affiliate, JP Development, in July 2012, our management team has successfully established a strategic midstream platform through us and JP Development by way of 25 third-party acquisitions and numerous organic capital projects. These include the acquisition of:
- •
- the Silver Dollar Pipeline System in October 2013;
- •
- our NGL transportation business in October 2013, consisting of approximately 43 hard shell tank trucks;
- •
- our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012;
- •
- our crude oil storage facility in Cushing, Oklahoma in August 2012;
- •
- our initial crude oil gathering and transportation operations, consisting of approximately 69 crude oil gathering and transportation trucks and our proprietary CAST software, in July 2012;
143
- •
- our cylinder exchange business in June 2012; and
- •
- 17 separate wholesale and retail propane businesses from July 2010 through July 2013.
We conduct our business through fee-based and margin-based arrangements.
Fee-based. We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide within our NGL distribution and sales segment. In our crude oil pipelines business, we purchase crude oil at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price. We consider this a fee-based business because we lock in the economic equivalent of a transportation fee. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from 1 month to 10 years.
Margin-based. We purchase and sell crude oil in our crude oil supply and logistics segment and NGLs and refined products in our NGL distribution and sales segment. A substantial portion of our margin related to the purchase and sale of crude oil in our crude oil supply and logistics segment is derived from "fee equivalent" transactions in which we concurrently purchase and sell crude oil at prices that are based on the same index, thereby generating revenue consisting of a margin plus our purchase, transportation, handling and storage costs. In our NGL distribution and sales segment, sales prices to our customers generally provide for a margin plus the cost of our products to our customers. We also perform blending services in our crude oil supply and logistics segment and our refined products terminals and storage segment, which allows us to generate additional margin based on the difference between our cost to purchase and blend the products and the market sales price of the finished blended product. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and cash flows. We expect to achieve this objective by pursuing the following business strategies:
- •
- Capitalize on organic growth opportunities and increase utilization of
our existing assets. We intend to identify and pursue organic growth opportunities and increase the utilization of our assets to
increase the cash flows of our existing businesses. These opportunities may include projects that grow throughput or storage volumes, expand margins, increase utilization of our assets or
differentiate the services we offer to create new market opportunities. For example, we have identified the following organic growth opportunities that we believe will enhance the profitability of our
businesses:
- •
- Crude oil businesses. Our Silver Dollar Pipeline System provides us with significant organic expansion opportunities in the Permian Basin. We intend to leverage our management team's expertise to grow our crude oil pipeline business through organic development projects that are designed to increase throughput by expanding our gathering footprint, adding interconnections to new markets and diversifying our customer base. The projects related to our Silver Dollar Pipeline System that we intend to commence during the next twelve months include (i) building new pipeline laterals, (ii) connecting new central
144
production facilities to the system pursuant to contractual arrangements with producer customers, (iii) adding to our storage capacity, (iv) building truck injection stations and (v) connecting the system to one or more additional interconnections with third party long-haul pipelines, which will broaden the scope of services and markets we are able to offer producers and provide our customers with more efficient and cost-effective ways to transport their products.
- We
are pursuing new customers currently operating in close proximity to our Silver Dollar Pipeline System in the Southern Wolfcamp within the
Permian Basin to maximize system capacity utilization and expand the gathering footprint of our pipeline system.
- Finally,
we intend to utilize our knowledge of matters related to crude oil supply and logistics to create opportunities to address the
infrastructure needs of developing crude oil basins. We believe this will allow us to significantly grow our operations in the Permian Basin, Mid-Continent and Eagle Ford shale. Please read
"—Our Assets and Operations—Crude Oil Supply and Logistics."
- •
- Refined products terminals and storage. We completed the
construction of ethanol blending units at our refined products terminal in North Little Rock, Arkansas in March 2014 and we intend to add ethanol blending units at our refined products terminal in
Cedar Mills, Texas in the second quarter of 2014 and butane blending capabilities at our North Little Rock terminal by the fourth quarter of 2014, which we believe will allow us to capture significant
blending opportunities and increase profits.
- •
- NGL distribution and sales. We recently completed the
expansion of our cylinder exchange business into all 48 states in the continental United States through the construction of two new production facilities and associated distribution depots
serving Arizona, California and Utah. We believe this expansion will provide us with economies of scale and significant cost savings in product procurement, transportation and general administration.
As a result of this expansion, we obtained a new three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to all of their gas stations
in California, Oregon and Washington. We believe that we will be able to compete for additional large-volume or national accounts due to our ability to provide services nationwide.
- •
- Technology and service enhancements. In addition to capital projects, we will also look to invest in new technologies that will enhance our operations and services. For instance, as part of the acquisition of our initial crude oil gathering and transportation assets, we acquired our proprietary CAST software, a tracking and logistics system that differentiates our services to producers by providing real-time updates of truck locations, crude oil specifications and volumes. Please read "—Our Assets and Operations—Crude Oil Supply and Logistics—CAST."
- •
- Pursue strategic and accretive acquisition opportunities from our affiliates and third parties. We intend to pursue accretive acquisition opportunities from our affiliates and third parties that will complement, expand and diversify our asset base and cash flows. In addition, we intend to leverage the industry relationships of our management team to generate additional acquisition opportunities.
Please read "Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2015" for more information regarding our forecast of the estimated distributable cash flow we may realize from the projects described above.
145
- •
- Acquisitions from JP Development and ArcLight. We believe
that our relationship with JP Development and ArcLight will provide us with future growth opportunities. JP Development has granted us a right of first offer on all of its current and future assets,
and ArcLight Fund V has granted us a right of first offer with respect to a 50% indirect interest in Republic Midstream, LLC, an ArcLight portfolio company ("Republic"). The right of first
offer with respect to JP Development's current and future assets is for a period of five years from the closing of this offering and the right of first offer with respect to Republic is for eighteen
months from the closing of this offering. A description of JP Development's current assets and Republic, which we collectively refer to as the ROFO Assets, is provided
below:
- •
- an approximately 115-mile intrastate crude oil pipeline, known as the Great Salt Plains Pipeline, that runs from Cherokee,
Oklahoma to Cushing, Oklahoma and serves the Mississippian Lime play;
- •
- an approximately 75-mile interstate crude oil pipeline, known as the Red River Pipeline, serving the Fort Worth Basin that
originates in Grayson County, Texas and runs to its principal terminus at the Elmore City Station in Garvin County, Oklahoma; and
- •
- a 100% member interest in Republic Midstream Gathering II, LLC, which owns a 50% indirect interest in Republic.
Republic has agreed to build, own and operate certain crude oil midstream assets for Penn Virginia Corp. in the Eagle Ford shale region. Republic's initial assets will consist of a 180-mile crude oil
gathering system in Gonzales and Lavaca Counties that will deliver the gathered volumes to a 144-acre central delivery terminal in Lavaca County that is capable of storing and blending crude oil
volumes. Republic has also agreed to construct a 12-inch, 30-mile takeaway pipeline from the central delivery terminal. Subject to entering into definitive documentation, we have agreed to perform
certain commercial services for Republic, including working with producers to transport crude oil from the wellhead to end markets.
- •
- Acquisitions from third parties. We are frequently
involved in discussions with third parties regarding the purchase of additional midstream assets. Historically, our acquisitions have largely been privately negotiated opportunities sourced through
our management team's proprietary relationships. Working together with our sponsor, we intend to continue to evaluate opportunities to acquire or develop other midstream assets that complement our
existing businesses, expand our geographic footprint and allow us to leverage our asset base and our management team's development and industry expertise.
- •
- Focus on fee-based and margin-based businesses with limited commodity price exposure. We intend to continue adding operations that focus on providing services to our customers under fee-based and margin-based arrangements. We plan to pursue opportunities in all of our segments with an emphasis on limiting commodity price exposure either through contract structure or through a managed hedging program. For example, to the extent we enter into fixed price product sales contracts in our NGL sales segment, we generally hedge our supply costs using financial swaps. Similarly, we hedge a majority of the forecasted volumes in our cylinder exchange business using financial swaps, where approximately half of our sales volumes are under contracts with two- and three-year terms that allow us to renegotiate prices at the time of contract renewal. We manage commodity price exposure in our crude oil supply and logistics business by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk."
146
- •
- Maintain financial flexibility and a disciplined capital structure. We intend to pursue a disciplined financial policy and maintain a conservative capital structure to allow us to pursue accretive acquisitions and execute on organic growth opportunities even in challenging capital market environments. Pro forma for this offering, we would have had $153.7 million in borrowing capacity under our revolving credit facility as of June 30, 2014. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $46.3 million as of June 30, 2014. Our credit facility contains an accordion feature that allows us to increase the borrowing capacity thereunder from $275 million to $425 million, subject to obtaining additional increased lender commitments. We believe our financial flexibility positions us to take advantage of future growth opportunities without incurring debt beyond appropriate levels.
We believe that we are well-positioned to successfully execute our business strategies by capitalizing on the following competitive strengths:
- •
- Stable cash flows from contractual arrangements and diversified
operations. Our contractual arrangements and diversified operations help us generate stable, predictable cash flows. We provide many of
our services under long-term or evergreen contracts with customers with whom we have longstanding relationships. Pursuant to our contractual arrangements, substantially all of our cash
flows are derived from fee-based or margin-based services with limited commodity price exposure. Our cash flows also benefit from our diverse operations in both geographic location and
services offered to our customers.
- •
- Crude oil pipelines and storage. The Silver Dollar
Pipeline System is underpinned by long-term, fee-based contracts with leading producers in the Southern Wolfcamp. One significant contract has a remaining term of approximately nine years and contains
an acreage dedication related to crude oil production from approximately 110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract with a remaining term of
approximately five years and containing a minimum volume commitment was amended in March 2014 to significantly increase the volumes committed thereunder. Our crude oil storage business operates under
a long-term contract with a remaining term of approximately 3.0 years as of June 30, 2014.
- •
- Crude oil supply and logistics. A substantial portion of
our margin related to the purchase and sale of crude oil in our crude oil supply and logistics segment is represented by "fee equivalent" transactions in which we concurrently purchase and sell crude
oil at prices that are based on the same index, thereby generating revenue consisting of a margin plus our purchase, transportation, handling and storage costs.
- •
- Refined products terminals and storage. Our refined
products terminals and storage segment operates under contracts with evergreen provisions consistent with industry practice so that, after an initial term of six months to two years, they can be
canceled upon 60 days' notice. For the six months ended June 30, 2014 approximately 90% of our customers have been doing business with us for over 10 years and these customers
account for approximately 2.7 million gallons per day of our terminals' throughput volumes.
- •
- NGL distribution and sales. We developed our NGL distribution and sales segment to generate consistent cash flows throughout the year. We believe that the combination of our spring- and summer-weighted cylinder exchange business with our fall- and winter-weighted NGL sales business reduces overall seasonal volatility in volumes. We generate revenues through margin-based arrangements in our NGL sales business. Our sales price per gallon consists of a margin plus our product supply, transportation, handling and storage costs, thereby limiting our commodity price exposure. Our fee-based NGL gathering and
147
- •
- Strategically located assets that provide organic growth
opportunities. The majority of our assets are located in areas characterized by strong demand for the services we currently provide as
well as a need for additional midstream infrastructure, providing us with attractive future growth prospects. Our assets and areas of operation
include:
- •
- crude oil pipelines, storage and supply and logistics businesses which are located in emerging, liquids-rich basins that
have seen accelerating production growth in recent years, such as the Permian Basin;
- •
- a refined products terminals and storage segment consisting of refined products terminals in North Little Rock, Arkansas
and Caddo Mills, Texas, which is situated in the Northeast portion of the Dallas-Fort Worth metroplex, a region expected to grow 23% by the year 2025 according to Census Bureau data;
- •
- a cylinder exchange business currently operating in all 48 states in the continental United States, which we believe gives
us the capability to compete for new large-volume or national accounts, as well as provides us with economies of scale and significant cost savings in product procurement, transportation and general
administration;
- •
- an NGL sales business located mostly in a six-state region in the Southwest and Midwest United States, which provides us
with the opportunity to target growing demand for propane in connection with power generation and other oilfield applications, thereby reducing our exposure to the seasonality of demand for propane as
a heating fuel; and
- •
- a fleet of approximately 43 hard shell tank trucks that transport NGLs and condensate for producers, gas processing
plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin.
- •
- Relationships with JP Development and
ArcLight. We consider our relationships with JP Development, our affiliate with whom we share a common management team, and ArcLight
Fund V, which has a substantial ownership interest in us, to be significant strengths. JP Development was formed in July 2012 by members of our management team and ArcLight for the express
purpose of supporting our growth. We acquired the Silver Dollar Pipeline System, a portfolio of crude oil supply and logistics assets and our fleet of NGL transportation trucks from JP Development in
February 2014 and we believe that our relationship with JP Development will provide us with future growth opportunities. We also believe that ArcLight Fund V's and our management's collective
ownership of (i) 95% of our general partner, which owns all of our incentive distribution rights, (ii) a 56.1% limited partner interest in us and (iii) 100% of the partnership
interests in JP Development creates a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the
overall value of our business. Please read "—Our Relationship with JP Development" for additional discussion of the JP Development Dropdown and the ROFO Assets.
- •
- Experienced and entrepreneurial management team. Our management team has a demonstrated track record of growing our business, identifying market opportunities in the areas in which we operate and making acquisitions. Averaging approximately 17 years of experience in the energy industry, our management team has expertise in key areas of the crude oil, refined products and natural gas liquids industries as well as in infrastructure development, acquisitions and the integration of acquired businesses. For example, since our formation in May 2010, our management team has successfully grown our and JP Development's operations through 25
transportation operations involve the transportation of NGLs by hard shell tank truck in exchange for a fee based on the number of gallons of NGLs we gather and the distance they are transported.
148
- •
- Strong sponsor with significant industry expertise. Through Lonestar, ArcLight Fund V is the principal owner of our general partner and the sole owner of JP Development. We believe that ArcLight Capital, which controls ArcLight Fund V, has substantial experience as a private equity investor in the energy industry, having managed the investment of more than $10 billion in energy companies and assets since its inception. By providing us with strategic guidance and financial expertise, we believe our relationship with ArcLight will greatly enhance our ability to grow our asset base and cash flows. We believe that our relationship with ArcLight strengthens our ability to make strategic acquisitions and to access other business opportunities. Upon the consummation of this offering, ArcLight Fund V will be the indirect owner of approximately 71% of our incentive distribution rights and a 51.2% limited partner interest in us. Due to ArcLight Fund V's significant economic interest in us, we believe that ArcLight will be motivated to promote and support the successful execution of our business strategies.
third-party acquisitions. Please read "—Our Acquisition History." In addition, our management team has established strong relationships with producers, marketers and refiners of crude oil throughout the upstream, midstream, refined products and natural gas liquids market segments, which we believe will be beneficial to us in pursuing acquisition and organic growth opportunities.
Our Relationship With JP Development and ArcLight
Our affiliate, JP Development, is a growth-oriented limited partnership that was formed in July 2012 by members of our management team and ArcLight for the express purpose of supporting our growth. JP Development intends to acquire growth-oriented midstream assets and to develop organic capital projects and then offer those assets for sale to us after they have been sufficiently developed such that their financial profile is suitable for us.
Since its formation, our management team and ArcLight have successfully grown JP Development through the acquisition of midstream assets and the execution of growth projects strategically located in our current areas of operation as well as new areas for expansion. In February 2014, we acquired from JP Development an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets for aggregate consideration valued at approximately $319 million. We refer to this transaction as the JP Development Dropdown. Please read "—JP Development Dropdown."
We believe that ArcLight Fund V's and our management's collective ownership of (i) 95% of our general partner, which owns all of our incentive distribution rights, (ii) a 56.1% limited partner interest in us and (iii) 100% of the partnership interests in JP Development create a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business. We believe that our relationship with JP Development and ArcLight will provide us with future growth opportunities, including the potential acquisition of the ROFO Assets.
Right of First Offer
JP Development has granted us a right of first offer for on all of its current and future assets, and ArcLight Fund V has granted us a right of first offer with respect to a 50% indirect interest in Republic, an ArcLight portfolio company. The right of first offer with respect to JP Development's current and future assets is for a period of five years from the closing of this offering and the right of first offer with respect to Republic is for a period of eighteen months from the closing of this offering. A description of JP Development's current assets and Republic, which we collectively refer to as the ROFO Assets, is provided below.
149
- •
- Great Salt Plains Pipeline. An approximately
115-mile intrastate crude oil pipeline that runs from Cherokee, Oklahoma to Cushing, Oklahoma that was placed in service in October 2012. The Great Salt Plains Pipeline has a current
capacity of approximately 27,000 bpd and JP Development has the capability to install two pump stations that will expand its capacity to in excess of 40,000 bpd. The Great Salt Plains
Pipeline serves the Mississippian Lime play and connects to (i) crude oil storage tanks owned by JP Development in Cherokee, Oklahoma with a shell capacity of approximately
170,000 barrels and (ii) leased crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels leased by us pursuant to a
long-term lease with a third party.
- •
- Red River Pipeline. An approximately 75-mile
interstate crude oil pipeline serving the Fort Worth Basin that originates in Grayson County, Texas and runs to its principal terminus at the Elmore City Station in Garvin County, Oklahoma. The Red
River Pipeline has a current capacity of approximately 5,000 bpd.
- •
- Republic Midstream. A 100% member interest in Republic Midstream Gathering II, LLC, which owns a 50% indirect interest in Republic. Republic has agreed to build, own and operate certain crude oil midstream assets for Penn Virginia Corp. in the Eagle Ford shale region. Republic's initial assets will consist of a 180-mile crude oil gathering system in Gonzales and Lavaca Counties that will deliver the gathered volumes to a 144-acre central delivery terminal in Lavaca County that is capable of storing and blending crude oil volumes. Republic has also agreed to construct a 12-inch, 30-mile takeaway pipeline from the central delivery terminal. Subject to entering into definitive documentation, we have agreed to perform certain commercial services for Republic, including working with producers to transport crude oil from the wellhead to end markets.
Please read "Certain Relationships and Related Party Transactions—Agreements With Affiliates in Connection With the Transactions—Right of First Offer Agreement" for additional information.
JP Development Dropdown
In February 2014, we acquired the following assets in the JP Development Dropdown in exchange for consideration valued at approximately $319 million:
- •
- Silver Dollar Pipeline System. The Silver Dollar Pipeline
System is a long-term contracted crude oil pipeline system consisting of approximately 50 miles of high-pressure steel pipeline in the core Southern Wolfcamp areas of Crockett, Reagan and Irion
counties in Texas, with throughput capacity of 100,000 bpd, truck terminals and truck injection stations, multiple receipt points and 40,000 barrels of crude oil storage. The Silver
Dollar Pipeline system came on-line in April 2013 and, for the six months ended June 30, 2014, transported an average of 19,652 barrels of crude oil per day.
- •
- Crude oil supply and logistics assets. A portfolio of
crude oil assets consisting of approximately 70 crude oil gathering and transportation trucks and approximately 30 truck injection stations that provide our customers with multiple outlets within a
market.
- •
- Natural gas liquids assets. Approximately 43 hard shell tank trucks engaged in the transportation of NGLs and condensate, including Y-grade, propane, butane and other NGLs, in the Eagle Ford shale and the Permian Basin and retail propane distribution assets in Arkansas and Missouri.
While our relationship with JP Development is a significant strength, it is also a source of potential conflicts. Please read "Conflicts of Interest and Duties" and "Risk Factors—Risks Inherent in an Investment in Us—Our general partner and its affiliates, including Lonestar, JP Development and ArcLight, have conflicts of interest with us and limited duties to us and our unitholders, and they may
150
favor their own interests to our detriment and that of our unitholders." Additionally, we have no control over JP Development's and ArcLight's business decisions or operations and JP Development is under no obligation to adopt a business strategy that favors us.
ArcLight Overview
ArcLight Fund V is managed by ArcLight Capital, a specialized private equity firm focused exclusively on the energy industry. ArcLight, through its five private equity funds, has invested more than $10 billion in over one hundred transactions since 2001. ArcLight invests across the entire energy industry value chain with a focus on North American energy infrastructure assets and companies. ArcLight's investment strategy is underpinned by a hands-on approach that seeks to substantially enhance the cash flow and asset value of its investments through multiple energy industry cycles. ArcLight's investment team has substantial expertise in energy investing, broad industry relationships and specialized asset-level value creation capabilities.
Crude Oil Pipelines and Storage
Crude Oil Pipelines
Silver Dollar Pipeline System. The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Southern Wolfcamp play in the Midland Basin. The system currently consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and an interconnection to a third-party long-haul transportation pipeline. Our operations are underpinned by long-term, fee-based contracts with leading producers in the Southern Wolfcamp. One significant contract has a remaining term of approximately nine years and contains an acreage dedication related to crude oil production from approximately 110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately five years and contains a minimum volume commitment that was amended in March 2014 to significantly increase the volumes committed thereunder.
The Silver Dollar Pipeline System is located in the core Southern Wolfcamp play within Crockett, Reagan and Irion counties, Texas, an emerging liquids-rich play being developed by several large oil and gas producers. According to data provided by Baker Hughes and Wood Mackenzie, approximately 5 million acres in these particular counties have experienced rapidly increasing rig count, growing approximately 80%, from 28 rigs in February 2011 to 51 in April 2014. Recent 30-day initial production rates have averaged approximately 425 barrels per day. The Southern Wolfcamp is a stacked play with multiple horizontal targets that can be accessed with a single well. If additional zones are proven through producer testing, Wood Mackenzie estimates that the total resource potential could increase to 10 billion Boe and allow producers to dramatically increase their number of drilling locations. As of June 2014, the Silver Dollar Pipeline System is connected to producers that control approximately 321,000 acres in Crockett County, Texas, and we are in advanced negotiations with other producers in the area to connect substantial additional acreage to the system and contract for additional minimum volume commitments. The table below contains operational information related to the Silver Dollar Pipeline System.
| |
|
|
Throughput for Six Months Ended |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
Length
|
Capacity | Storage Capacity | December 31, 2013 | June 30, 2014 | ||||||||
50 miles |
100,000 bpd | 40,000 barrels | 13,738 bpd | 19,652 bpd | ||||||||
151
Construction of the Silver Dollar Pipeline System began in October 2012, and it was put into service in April 2013. The pipeline extends from the Midway Station in Crockett County, Texas to the Owens Station in Reagan County, Texas, a 4.3-acre site with an interconnection to Plains All American Pipeline, L.P.'s Spraberry Expansion. The Midway Station is strategically located in the heart of the Southern Wolfcamp. It receives trucking volumes from multiple producers located to the south and has connections to neighboring producer facilities. The Midway Station currently has a 10,000 barrel tank and four truck injection stations.
In our crude oil pipelines business, we purchase crude oil from a producer or supplier at a designated receipt point on our Silver Dollar Pipeline System at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, allowing us to lock in a fixed margin that is in effect economically equivalent to a transportation fee. These transactions account for substantially all of the Adjusted EBITDA we generate on our Silver Dollar Pipeline System.
Expansion projects. Anticipated commercial opportunities in the Southern Wolfcamp have allowed us to commit to our current expansion plans for the Silver Dollar Pipeline System, including an interconnection to a second long-haul transportation pipeline, which we expect to complete in the fourth quarter of 2014. These expansion projects will increase the length of the Silver Dollar Pipeline System by approximately 30 miles and significantly increase gathering and take-away capacity. We believe that expanding the pipeline in this manner will allow us to obtain volume commitments from new customers and transport additional committed volumes for a customer who amended its existing long-term contract with us in March 2014 to significantly increase the volumes committed thereunder.
Crude Oil Storage
We own a crude oil storage facility in Cushing, Oklahoma with an aggregate shell capacity of approximately 3.0 million barrels, consisting of five 600,000-barrel storage tanks. These storage tanks
152
were built in 2009 and are located on the western side of a terminal owned by Enterprise Product Partners L.P. (the "Enterprise Terminal"). The storage tanks are able to receive approximately 22,000 barrels of crude oil per hour or deliver approximately 8,000 barrels of crude oil per hour, and have inbound connections with multiple pipelines and two-way interconnections with all of the other major storage facilities in Cushing, including the delivery point specified in all crude oil futures contracts traded on the NYMEX. TEPPCO Partners LP ("TEPPCO"), a wholly owned subsidiary of Enterprise, serves as the operator of our facilities.
Our crude oil storage business provides stable and predictable fee-based cash flows. All of the shell capacity of our storage tanks is dedicated to one customer pursuant to a long-term contract, backed by a letter of credit, with a remaining term of approximately 3.0 years as of June 30, 2014. Our customer has the option to extend this contract up to two years pursuant to a renewal option. We generate crude oil storage revenues by charging this customer a fixed monthly fee per barrel of shell capacity that is not contingent on the customer's actual usage of our storage tanks.
Our storage facility is on land that is subject to a 50-year lease with TEPPCO. We have the option to extend our lease by up to an additional 30 years. Our location in the Enterprise Terminal provides our customer with access to multiple pipelines outbound from Cushing, including a manifold connecting our tanks to the Enterprise Terminal. The Enterprise Terminal is connected to the Seaway Pipeline, which is owned and operated by Enterprise and Enbridge Inc. and transports crude oil from Cushing to the Gulf Coast.
We are party to an operating agreement pursuant to which an affiliate of TEPPCO operates and maintains the crude oil storage tanks located at our crude oil storage facility and provides us with certain services, including services related to product movements, data tracking, station operations (including documentation and inspection programs), financial and accounting matters and purchases of material. These services are provided to us at a monthly base rate and we are permitted to request additional services from TEPPCO, which are provided to us at cost. TEPPCO is obligated to perform the services as a reasonably prudent operator and in accordance with all applicable laws and accepted industry practices. The operating agreement contains certain other customary terms, including provisions relating to restrictions on assignment, terms of payment, indemnification, confidentiality and dispute resolution. The operating agreement remains in place for the same term as the lease agreement described above.
The design and construction specifications of our storage tanks meet or exceed the minimums established by the American Petroleum Institute. Our storage tanks also undergo regular maintenance and inspection programs, and we believe that these design specifications and maintenance and inspection programs help to reduce our maintenance capital expenditures.
Organic growth opportunities. We believe that the experience and knowledge we have obtained in our crude supply and logistics segment gives us early insight into the infrastructure needs of developing crude oil basins. We believe that significant new drilling activity in the Permian Basin, Eagle Ford shale, Granite Wash play and Mississippian Lime play will result in crude oil production growing faster than available takeaway capacity over the medium term. As an early mover in areas with significant production of crude oil, we believe our established relationships with highly active producers and marketers in these regions will provide us with opportunities to expand our crude oil pipelines and storage segment through the construction of additional infrastructure.
Crude Oil Supply and Logistics
Our crude oil supply and logistics segment manages the physical movement of crude oil from origination to final destination largely through our network of owned and leased assets. Our assets and operations are located in areas of substantial crude oil production growth, including the Permian Basin, Mid-Continent and Eagle Ford shale. We own and operate a fleet of approximately 135 crude oil
153
gathering and transportation trucks and approximately 30 crude oil truck injection stations and terminals. We also lease crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels pursuant to a long-term lease with a third party. Due to the limited pipeline infrastructure in some of the basins in which we operate, our crude oil gathering and transportation trucks provide immediate access for customers to transport their crude oil to the most advantageous outlets, including pipelines, rail terminals and local refining centers.
We primarily generate revenues in our crude oil supply and logistics segment by purchasing crude oil from producers, aggregators and traders at an index price less a discount and selling crude oil to producers, traders and refiners at a price linked to the same index. The majority of activities that are carried out within our crude oil supply and logistics segment are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside opportunities. During the year ended December 31, 2013 and the six months ended June 30, 2014, we purchased an average of 53,471 barrels per day and 42,411 barrels per day, respectively, of crude oil entirely in the Mid-Continent region. We intend to utilize our knowledge of matters related to crude oil supply and logistics to create opportunities to address the infrastructure needs of developing crude oil basins. We believe this will allow us to significantly grow our operations in the Permian Basin, Mid-Continent and Eagle Ford shale.
In general, sales prices referenced in the underlying contracts, most of which have a 30-day evergreen term, are market-based and may include pricing differentials for such factors as delivery location or crude oil quality. Our crude oil supply and logistics operations generate substantial revenues and cost of products sold as a result of the significant volume of crude oil bought and sold. While the absolute price levels of crude oil significantly impact revenues and cost of products sold, such price levels normally do not bear a relationship to gross profit for crude oil sales generated under buy/sell contracts. As a result, period-to-period variations in revenues and cost of products sold are not generally meaningful in analyzing the variation in gross profit for our crude oil supply operations.
We also generate revenue in this segment by performing blending services whereby we purchase varying qualities of crude oil from our producer and logistics customers, which we blend in our leased storage tanks to WTI or other specifications. The level of profit associated with our blending operations is influenced by overall contract structure and the degree of market volatility, as well as variable operating expenses. Please read "—How We Conduct Our Business" for more details on these contractual arrangements.
We mitigate the commodity price exposure of our crude oil supply and logistics operations by limiting our net open positions through the concurrent purchase and sale of like quantities of crude oil intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. All of our supply activities are subject to our comprehensive risk management policy, which establishes limits in order to manage risk and mitigate our commodity price exposure.
Our crude oil gathering and transportation trucks currently have excess capacity and we are focused on increasing the utilization of our current fleet. We typically assign crude oil gathering and transportation trucks to a specific area but can temporarily relocate them to meet demand as needed.
CAST. We equip our drivers with advanced computer technology and dispatch them from central locations in Tulsa, Oklahoma, Whitesboro, Texas and Pratt, Kansas. We believe that our proprietary CAST software, which is employed by our entire fleet of crude oil gathering and transportation trucks, provides us with a competitive advantage by allowing us to offer our customers a differentiated level of service. Our drivers are provided with hand-held computers which allow them to utilize our CAST software after they have loaded product. Our CAST software is a centralized system for dispatch, electronic ticket management, reporting, operations data management and lease data management. The CAST software validates ticket data in the field to greatly improve accuracy relative to paper tickets and provides our customers with near real-time views of dispatch, truck tickets, vehicle location, load
154
acceptances and rejections and drivers. The CAST software also offers our customers flexible reporting options by providing customized data to the customer in the format that works best for its accounting and marketing needs.
Refined Products Terminals and Storage
Our refined products terminals and storage segment is comprised of two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our refined products terminals are facilities where refined products are transferred to or from storage or transportation systems, such as pipelines, to other transportation systems, such as trucks. Our refined products terminals play a key role in moving product to the end-user market by providing the following services:
- •
- receipt, storage, inventory management and distribution;
- •
- blending and injection of additives to achieve specified grades of gasoline; and
- •
- other ancillary services that include heating of bio-diesel, product transfer and railcar handling services.
Our refined products terminals consist of multiple storage tanks with a combined aggregate storage capacity of 1.3 million barrels and are equipped with automated truck loading equipment that is operational 24 hours per day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by the terminal and our customers. In addition, our refined products terminals are equipped with truck loading racks capable of providing automated computer blending to individual customer specifications.
We generate fee-based revenues in our refined products terminals and storage segment from:
- •
- throughput fees based on the receipt, storage and redelivery of refined products, including fees based on the volume of
product redelivered from the terminal and storage fees based on a rate per barrel of storage capacity per month;
- •
- additive service fees based on ethanol and biodiesel used in blending services and for additive injection; and
- •
- ancillary fees for the heating of bio-diesel, product transfer and railcar handling services.
Our refined products terminals and storage segment generates its fee-based revenues pursuant to contracts that typically contain evergreen provisions consistent with industry practice so that, after an initial term of six months to two years, they can be canceled upon 60 days' notice. We also generate revenues from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. A majority of the customers in our refined products terminals and storage segment are large, well-known oil companies and independent refiners with whom we have longstanding relationships.
The following table highlights the storage capacity, number of loading lanes, number of tanks, supply source, mode of distribution and average daily throughput of our refined products terminals:
| |
|
|
|
|
|
Approximate Average Throughput (gallons per day) for the |
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Terminal Location
|
Shell Storage Capacity (bbls) | Loading Lanes | Number of Tanks | Supply Source | Mode of Redelivery | Year Ended December 31, 2013 |
Six Months Ended June 30, 2014 |
|||||||||||||
Little Rock, AR |
550,000 | 8 | 11 | Pipeline, Rail and Truck |
Truck | 2,227,159 | 1,932,552 | |||||||||||||
Caddo Mills, TX |
770,000 | 5 | 10 | Pipeline and Truck |
Truck | 674,222 | 765,425 | |||||||||||||
155
North Little Rock terminal. Our North Little Rock terminal consists of 11 storage tanks with an aggregate capacity of approximately 550,000 barrels and has eight loading lanes with automated truck loading equipment to minimize wait time for our customers. Our truck loading racks are capable of providing automated computer blending to customer specifications. The North Little Rock terminal handles products such as multi-octane conventional gasoline, ultra-low sulphur diesel with dye-at-rack capability, bio-diesel with ratio blending capability and ethanol. This terminal is supplied by two receipt lines from the TEPPCO Pipeline, one for ultra-low sulphur diesel and the other for all other refined products, and has full offloading capability for 10 rail cars of ethanol at a time via a rail spur served by the Union Pacific system via the Arkansas Midland Railroad. Our North Little Rock terminal serves the Little Rock metropolitan area, which grew 15% from 2000 to 2010 according to Census Bureau data, and is expected to grow another 11% by 2025.
Caddo Mills terminal. Our Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment to minimize wait time for our customers. This terminal is served by the Explorer Pipeline and has truck loading racks capable of providing automated computer blending to customer specifications. Our Caddo Mills terminal handles products such as conventional blend stock for oxygenate blending (CBOB) gasoline, reformulated blend stock for oxygenate blending (RBOB), premium blend stock for oxygenate blending (PBOB), ethanol, ultra-low sulphur diesel with dye-at-rack capability and bio-diesel with ratio blending capability. We own approximately 6 additional acres of land at our Caddo Mills terminal that is available for future expansion. Management estimates that this acreage is capable of housing an additional 200,000 barrels of storage capacity. The Caddo Mills terminal serves Collin County, located in the northeast portion of the Dallas-Fort Worth metroplex, which, according to Census Bureau data, grew 23% from 2000 to 2010, making it one of the fastest growing large markets in the United States.
Organic growth opportunities. We have identified organic growth opportunities that we believe will enhance the profitability of our refined products terminals and increase third-party throughput volumes running through our existing system, including the following:
Butane blending. We intend to add butane blending capabilities at our North Little Rock terminal, which we believe will allow us to capture significant blending opportunities and increase profits.
NGL Distribution and Sales
Cylinder Exchange
We currently operate the third-largest propane cylinder exchange business in the United States, which consists of the distribution of propane-filled cylinder tanks typically used in barbeque grilling and which covers all 48 states in the continental United States through a network of over 17,700 distribution locations. We market our business under the brand name Pinnacle Propane Express or under the brand names of our customers. Our customers include grocery stores, pharmacies, convenience stores and hardware retailers which sell or exchange our propane-filled cylinders to consumers for end-use. For the year ended December 31, 2013, on a combined pro forma basis, we sold or exchanged approximately 4.5 million propane cylinders containing approximately 15.8 million aggregate gallons of propane, representing a 7% increase in cylinder sales and exchanges compared to the same period during the previous year. For the six months ended June 30, 2014, we sold or exchanged approximately 2.5 million propane cylinders containing approximately 8.9 million aggregate gallons of propane, representing a 10% increase in cylinder sales and exchanges compared to the same period during the previous year. We believe our cylinder exchange business is strategically positioned for continued growth resulting from the overall increase in demand and extended applications for portable propane cylinders and our recently completed expansion in the western United States.
156
We generate revenues in our cylinder exchange business through the sale or exchange of propane-filled cylinders at an agreed upon contract price. For the year ended December 31, 2013 and the six months ended June 30, 2014, we distributed 51% and 56%, respectively, of our propane volumes in our cylinder exchange business under long-term agreements and the remaining 49% and 44%, respectively, under one-month contracts or on a spot/demand basis. As of June 30, 2014, our contracts had a weighted average remaining term of approximately one year. Our long-term cylinder exchange agreements typically permit us to adjust our prices at the time of contract renewal while our month-to-month cylinder exchange agreements allow us to pass our costs on to our customers and thereby minimize our commodity price exposure. In order to manage our cost of propane we enter into hedging arrangements on all fixed-price contracts. We use financial swaps to hedge a majority of the forecasted volumes in our cylinder exchange business, where approximately half of our sales volumes are under contracts with two- and three-year terms.
Cylinder production cycle. We own 11 production facilities strategically located in Alabama, Illinois, Michigan, Missouri, Nevada, Oregon, Pennsylvania, South Carolina and Texas. Our production facilities receive inbound pallets of empty 20-pound propane cylinders, which are put through a processing cycle that includes cleaning, inspection, testing, painting, refilling and loading onto relay trucks for delivery to our 57 distribution depot locations. Drivers at our depots receive the full cylinders from our production facilities for delivery to our customer service locations and pick up empty cylinders, which are shipped to our production facilities for processing.
Nationwide expansion. We recently finished an expansion of our cylinder exchange business through the construction of distribution depots and two new production facilities serving Arizona, California, Oregon, Utah and Washington. We believe that this expansion will allow us to compete for new large-volume or national accounts due to our ability to provide services nationwide and will provide us with economies of scale and significant cost savings in product procurement, transportation and general administration. For example, we recently entered into a new three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to all of their gas stations in California, Oregon and Washington. We believe a national presence will give us advantages over smaller competitors and will make us one of the few propane distributors that can competitively provide cylinder exchange services on a nationwide basis, including to leading big box, hardware, grocery, convenience and drug store chains.
NGL Sales
Our NGL sales business involves the retail, commercial and wholesale sale of NGLs and other refined products (including sales of gasoline and diesel to our oilfield service and agricultural customers) in six states in the Southwest and Midwest to approximately 88,800 customers through our distribution network of 44 customer service locations. We generate revenues by charging a price per gallon consisting of our product supply, transportation, handling, and storage costs plus a margin. Our contracts permit us to pass through our supply costs on a regular basis, thereby limiting our commodity price exposure. Since July 2010, we have acquired 17 propane franchises to expand our market presence within our operating region in Texas, Oklahoma, New Mexico, Arizona, Arkansas and Missouri.
Customers. We sell propane, butane and refined fuels, including diesel, gasoline, lubricants and solvents, primarily to three customer markets: retail, commercial and wholesale, which include a mix of residential, commercial, agricultural, oilfield service and industrial customers. The customer service centers in our NGL sales business are located in suburban and rural areas where natural gas is not readily available. These customer service centers generally consist of an office, warehouse and service facilities, with one or more 2,500 to 45,000 gallon storage tanks on the premises. These tanks are used
157
to supply our bobtail trucks, which in turn make deliveries to our retail customers. Customers can also bring their own NGL storage containers to our customer service centers to be filled.
Retail. We primarily serve residential customers through the sale of propane for home heating and power generation. We deliver propane through our 124 active bobtail trucks, which have capacities ranging from 2,000 gallons to 5,000 gallons of propane into stationary storage tanks on our customers' premises. Tank ownership and control at customer locations are important components of our operations and customer retention, and account for approximately half of our retail volumes. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 12,000 gallons, with a typical tank having a capacity of 250 to 500 gallons. We also offer a propane supply commitment program to customers who own their own tanks that we believe increases customer loyalty. Under the program, customers receive progressively larger discounts off our posted prices each year that they remain as our customer. We also offer our customers a budget payment plan whereby the customer's estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period.
In Arizona, our subsidiary, Alliant Arizona Propane L.L.C., sells propane to residential and commercial customers through regulated central distribution systems in Payson and Page, Arizona that utilize pipelines to distribute propane through meters at the customer's location. Alliant Arizona Propane L.L.C. is a regulated utility that receives a fixed cost-plus fee for propane sold. Another subsidiary, Alliant Gas, serves 25 communities in Texas and two communities in Arizona through regulated central distribution systems pursuant to long-term contracts. Net customer turnover at Alliant Gas is nearly zero.
Commercial. Our commercial customers include a mix of industrial customers, hotels, restaurants, churches, warehouses and retail stores. These customers generally use propane for the same purposes as our residential customers as well as industrial, oilfield service and agricultural customers, who use propane and refined fuels, such as gasoline and diesel, for heating requirements and as fuel to power over-the-road vehicles, forklifts and stationary engines.
Wholesale. Our wholesale customers are principally governmental agencies and other propane distributors. Our LPG transports, which are large trucks that have capacities ranging from 9,000 to 11,500 gallons, load propane at third-party supply points for delivery directly to tanks located on the property of our wholesale customers.
Product supply. We utilize 20 domestic sources of propane supply, including spot market purchases, with four suppliers providing a substantial portion of our propane. Our propane supply contracts are typically form agreements with one-year terms and standard commercial provisions. During the year ended December 31, 2013 and the six months ended June 30, 2014, we purchased the majority of our propane needs from these four suppliers.
Our supply group manages and sources propane to ensure secure and reliable supply throughout the year. Our LPG transports pick up propane at our supply points, typically refineries, natural gas processing and fractionation plants or LPG storage terminals, for delivery to our customer service centers and our wholesale customers. Supplies of propane from our sources historically have been readily available. During the combined pro forma year ended December 31, 2013 and the six months ended June 30, 2014, approximately 76% and 80%, respectively, of our propane supply was purchased under supply agreements, which typically have a term of one year, and the remainder on the spot market.
Our supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas or (ii) posted prices at the time of delivery. We use a variety of delivery methods, including LPG transports, to transport propane from suppliers to our customer service locations as well as various
158
third-party storage facilities and terminals located in strategic areas across our area of operations. In order to manage our cost of propane, we enter into hedging arrangements on all fixed-price contracts.
NGL Transportation
In February 2014 we expanded our NGL distribution and sales segment by acquiring a fleet of approximately 43 hard shell tank trucks that gather and transport NGLs and condensate for producers, gas processing plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin. For the year ended December 31, 2013 and the six months ended June 30, 2014, on a pro forma basis, our NGL transportation trucks transported approximately 203,005 gallons per day and 250,240 gallons per day, respectively, of NGLs.
Crude oil pipelines and storage. We are subject to competition from other crude oil pipelines, crude oil storage tank operators and crude oil marketing companies that may be able to transport or store crude oil at more favorable prices or transport crude oil greater distance or to more favorable markets. We compete with national, regional and local crude oil pipeline transportation and storage companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in our crude oil storage segment include Plains All American Pipeline, L.P., Occidental Petroleum Corporation, SemGroup Corporation, Rose Rock Midstream, L.P., Blueknight Energy Partners, L.P. and Enterprise Products Partners L.P.
Crude oil supply and logistics. We are subject to competition from other providers of crude oil supply and logistics services that may be able to supply our customers with the same or comparable services on a more competitive basis. We compete with national, regional and local storage, gathering, transportation and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in this segment include Plains All American Pipeline, L.P., Rose Rock Midstream, L.P., Blueknight Energy Partners, L.P., SemGroup Corporation, Sunoco Logistics, Enterprise Products Partners L.P., Genesis Energy, L.P. and NGL Energy Partners L.P.
Refined products terminals and storage. Our refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas compete with other independent terminals on price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading activities. In the North Little Rock, Arkansas market, these competitors include Magellan Midstream Partners LP and HWRT Oil Company, LLC. In Dallas, Texas, the market served by our Caddo Mills, Texas terminal, these competitors include Valero Energy Corporation, Delek Logistics Partners, LP, Magellan Midstream Partners LP and Flint Hills Resources LP.
NGL distribution and sales. In addition to competing with suppliers of other energy sources such as natural gas, our NGL distribution and sales segment competes with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. The large, full-service multi-state marketers we compete with include Ferrellgas, L.P. and AmeriGas Partners, L.P. Each of our customer service centers operates in its own competitive environment because retail marketers tend to be located in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.
159
Weather conditions have a significant impact on the demand for our products, particularly propane and refined fuels for heating purposes. Many of our customers rely on propane primarily as a heating source. Accordingly, the volumes sold are directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures, as was the case in the heating season over the last three years throughout our operating territories, will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption. Meanwhile, our cylinder exchange operations experience higher volumes in the spring and summer, which includes the majority of the grilling season. Sustained periods of poor weather, particularly in the grilling season, can negatively affect our cylinder exchange revenues. In addition, poor weather may reduce consumers' propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange.
The volume of propane used by customers of our NGL sales business is higher during the first and fourth calendar quarters and lower during the second and third calendar quarters. Conversely, the volume of propane that we sell through our cylinder exchange business is higher during the second and third calendar quarters and lower in the first and fourth calendar quarters. We believe that our combination of our winter-weighted NGL sales business with our higher-margin, summer-weighted cylinder exchange business reduces overall seasonal fluctuations in volumes and financial results, as our cylinder exchange business is more active in summer months and our NGL sales business is more active in winter months. The impact of seasonality is also mitigated by non-heating related demand throughout the year for propane for oilfield services, fuel for automobiles and for industrial applications, such as forklifts, mowers and generators. On a pro forma basis for the year ended December 31, 2013, we sold approximately 65 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 41% in the second and third quarters of 2013 and 59% in the first and fourth quarters of 2013.
The volume of product that is handled, transported, throughput or stored in our refined products terminals is directly affected by the level of supply and demand in the wholesale markets served by our terminals. Overall supply of refined products in the wholesale markets is influenced by the absolute prices of the products, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the market's perception of future product prices. Although demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, most of the revenues generated at our refined products terminals do not experience any effects from such seasonality. However, the butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain our own property, business interruption and pollution liability insurance policies at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets. As we continue to grow, we will continue to evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.
160
Regulation of the Industry and Our Operations
Crude Oil
We own and operate a fleet of trucks to transport crude oil. We are licensed to perform both intrastate and interstate motor carrier services and are subject to certain safety regulations issued by the DOT. DOT regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment and many other aspects of our trucking operations. Our trucking operations are also subject to regulations and oversight by the Occupational Safety and Health Administration. Additionally, our Silver Dollar Pipeline System is subject to the regulatory oversight of the Texas Railroad Commission and the DOT's Pipeline and Hazardous Materials Safety Administration ("PHMSA").
Refined Products and NGLs
All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. We maintain various permits necessary to ensure that our operations comply with applicable regulations. We conduct training programs to help ensure that our operations are in compliance with applicable governmental regulations. With respect to general operations, certain National Fire Protection Association ("NFPA") Pamphlets, including Nos. 54 and 58 and/or one or more of various international codes (including international fire, building and fuel gas codes) establish rules and procedures governing the safe handling of propane, or comparable regulations, which have been adopted by all states in which we operate. In addition, Alliant Arizona Propane, LLC is subject to regulation by the Arizona Corporation Commission and Alliant Gas, LLC is subject to regulation by the Texas Railroad Commission. We believe that the policies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.
With respect to the transportation of NGLs, including propane, by truck, we are subject to regulation by PHMSA under the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, among other statutes. Our propane gas pipeline systems are also subject to regulation by the PHMSA under the Natural Gas Pipeline Safety Act of 1968, which applies to, among other things, a propane gas system that supplies ten or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT's pipeline safety regulations require operators of all gas systems to train employees and third-party contractors, establish written procedures to minimize the hazards resulting from gas pipeline emergencies and conduct and keep records of inspections and testing.
PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas ("HCAs"), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators, including us, to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified
161
minimum yield strength in high consequence areas. Effective October 25, 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum operating pressure. We have performed hydrotests of our facilities to confirm the maximum operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum operating pressure would materially affect our operations or revenue.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most states are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines.
Management believes that the policies and procedures currently in effect at all of our propane gas systems are consistent with industry standards and are in compliance with applicable law. Due to our ownership and control of these gas utility companies, we are required to notify FERC of our status as a holding company. We recently filed such a notification of holding company status and we qualified for an exemption from FERC accounting regulations and access to our books and records because we are a holding company solely by reason of our interests in local gas distribution systems.
General
Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of certain terminals, storage and transportation facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
- •
- requiring the installation of pollution-control equipment or otherwise restricting the way we operate;
- •
- limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited
by endangered or threatened species;
- •
- delaying system modification or upgrades during permit reviews;
- •
- requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to
former operations; and
- •
- enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or permit requirements imposed by such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
162
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes
163
disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Oil Pollution Act
In 1991, the EPA adopted regulations under the Oil Pollution Act, or OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
Air Emissions
Our operations are subject to the CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA proposed a final rule on June 7, 2012. The EPA published the final rule on January 30, 2013. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. We are currently in compliance with the rule. On August 29, 2013, the EPA issued a notice of its intent to reconsider issues related to the use of emergency stationary engines and engines in certain non-emergency situations. This reconsideration does not otherwise affect the January 2013 regulations.
On June 28, 2011, the EPA issued a final rule modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new,
164
modified and reconstructed stationary internal combustion engines. The rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. The EPA issued minor amendments to the rule on January 30, 2013. We are currently in compliance with the rule.
Water Discharges
The Federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.
Safe Drinking Water Act
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We believe that our facilities will not be materially adversely affected by such requirements.
Endangered Species
The Endangered Species Act ("ESA") restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas. Moreover, as a result of a settlement approved by the United States District Court for the District of Columbia on September 9, 2011, the United States Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011 settlement, the United States Fish and Wildlife Service is required to review and address the needs of more than 250 species on the candidate list over a 6-year period. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and propane exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers' performance of operations, which could reduce demand for our services.
165
National Environmental Policy Act
The National Environmental Policy Act ("NEPA") establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012 issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
Hydraulic Fracturing
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities. However, a portion of our suppliers' and customers' hydrocarbon production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process.
Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts. The EPA released a progress report on its study on December 21, 2012, and stated that a draft report of the findings of the study is expected in late 2014. In addition, in October 2011, the EPA announced its intention to propose regulations by 2014 under the Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. In May 2012, the Bureau of Land Management issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the Bureau of Land Management ("BLM") after fracturing operations have been completed, and includes provisions addressing wellbore integrity and flowback water management plans. The Department of the Interior published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water.
Several states, including Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.
On April 17, 2012, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants ("NESHAPS") programs. These rules also include NSPS for completions of hydraulically fractured oil and gas wells. These standards
166
include the reduced emission completion ("REC") techniques developed in EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology ("MACT") standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. At this point, the effect these proposed rules could have on our business, and that of our customers and suppliers, has not been determined. While these rules have been finalized, many of the rules' provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.
Climate Change
In the United States, legislative and regulatory initiatives are underway to limit GHG emissions. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. The Supreme Court determined that GHG emissions fall within the federal CAA definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the CAA.
In addition, on September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012.
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the Supreme Court held in its June 2011 decision in American Electric Power Co., Inc. v. Connecticut that with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question whether tort claims against GHG emissions sources alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.
167
Anti-terrorism Measures
Certain of our bulk storage facilities are also subject to regulation by the Department of Homeland Security ("DHS"). The Department of Homeland Security Appropriation Act of 2007 requires the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.
We utilize a variety of trademarks and tradenames which we own, including "Pinnacle Propane," "Pinnacle Propane Express" and "Alliant Arizona Propane." We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.
Title to Properties and Permits
We believe that we have satisfactory title to all of the assets that we own. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us, we believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.
We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for us to operate our business in all material respects as described in this prospectus. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations will be obtained after the closing of this offering or that the failure to obtain these consents, permits or authorizations will not have a material adverse effect on the operation of our business.
Our general partner maintains its headquarters in Irving, Texas. We also have satellite offices located in Houston, Texas, Whitesboro, Texas, Shreveport, Louisiana, North Little Rock, Arkansas, Pratt, Kansas and Gurnee, Illinois. The current lease of our general partner's headquarters expires in 2019. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.
We are managed and operated by the board of directors and executive officers of our general partner. Neither we nor our subsidiaries will have any employees. Our general partner will have the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business will be employed by our general partner. As
168
of June 30, 2014, our general partner and its affiliates have approximately 827 employees performing services for our operations. None of these employees are covered by collective bargaining agreements and we believe that our general partner and its affiliates have a satisfactory relationship with their employees.
At any time, we are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our combined liabilities may change materially as circumstances develop.
169
Management of JP Energy Partners LP
We are managed by the directors and executive officers of our general partner, JP Energy GP II LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Lonestar and members of our management directly own 95% of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors and cannot directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
Following the closing of this offering, we expect that our general partner will have eight directors, including two independent director nominees who will become members of our general partner's board of directors prior to the closing of this offering. We expect that Patrick J. Welch, our Executive Vice President and Chief Financial Officer, will also be appointed to our general partner's board of directors prior to the closing of this offering. The members of our general partner, including Lonestar, will appoint all members to the board of directors of our general partner. In accordance with the NYSE's phase-in rules, we will have at least three independent directors within one year of the date our common units are first listed on the NYSE. Our board has determined that T. Porter Trimble and Norman J. Szydlowski, director nominees who will become members of our board of directors prior to the closing of this offering, are independent under the independence standards of the NYSE.
Neither we nor our subsidiaries will have any employees. Our general partner will have the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business will be employed by our general partner, but we sometimes refer to these individuals in this prospectus as our employees.
Director Independence
Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.
Committees of the Board of Directors
The board of directors of our general partner will have an audit committee, a compensation committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.
Audit Committee
T. Porter Trimble, Norman J. Szydlowski and Lucius H. Taylor will serve as the initial members of our audit committee. Our general partner initially may rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. In compliance with the rules of the NYSE, our general partner will appoint a third independent director to our board of directors within
170
one year of the closing of this offering. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.
Compensation Committee
At least three members of the board of directors of our general partner will serve on our compensation committee. The compensation committee will establish salaries, incentives and other forms of compensation for officers and other employees. The compensation committee will also administer our incentive compensation and benefit plans. The NYSE does not require publicly traded partnerships, such as us, to have a compensation committee or, if we voluntarily elect to have a compensation committee, require that the members of the compensation committee be independent directors.
Conflicts Committee
At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. T. Porter Trimble and Norman J. Szydlowski will serve as the initial members of the conflicts committee. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than (i) common units and (ii) awards under our incentive compensation plan. Any matters approved by our conflicts committee will be presumed to have been approved in good faith, will be deemed to be approved by all of our partners and will not be a breach by our general partner of any duties it may owe us or our unitholders.
Directors and Executive Officers of JP Energy GP II LLC
Directors are elected by the members of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors, director nominees and executive officers of JP Energy GP II
171
LLC. Each of our director nominees will become members of our board of directors prior to the closing of this offering.
Name
|
Age | Position with JP Energy GP II LLC | |||
|---|---|---|---|---|---|
J. Patrick Barley |
40 | Chairman of the Board, President and Chief Executive Officer | |||
Patrick J. Welch |
47 | Executive Vice President, Chief Financial Officer and Director Nominee | |||
Jeremiah J. Ashcroft III |
42 | Executive Vice President and Chief Operating Officer | |||
Jon E. Hanna |
49 | Executive Vice President—Commercial and Business Development | |||
Christopher Hill |
40 | Senior Vice President—NGL Distribution and Sales | |||
Scott Smith |
50 | Senior Vice President—Crude Oil Supply and Logistics | |||
John F. Erhard |
40 | Director | |||
Daniel R. Revers |
52 | Director | |||
Lucius H. Taylor |
40 | Director | |||
Greg Arnold |
51 | Director | |||
T. Porter Trimble |
54 | Director Nominee | |||
Norman J. Szydlowski |
63 | Director Nominee | |||
J. Patrick Barley. J. Patrick Barley has served as President, Chief Executive Officer and Chairman of the board of directors of our general partner since May 2010. Mr. Barley brings over 15 years of experience managing early-stage investments. Prior to founding JP Energy Partners, Mr. Barley was the Founder, President and Chief Executive Officer of Lonestar Midstream Partners, LP ("Lonestar Midstream"), a midstream company focused on natural gas gathering and processing, from March 2005 to July 2008. Mr. Barley managed his private investments from the sale of Lonestar Midstream to Penn Virginia Resources Partners LP in July 2008 until he founded JP Energy Partners in May 2010. In 2004, Mr. Barley formed his own private investment firm, CB Capital, LLC, which served as the general partner of Lonestar Midstream. Prior to forming CB Capital, LLC, Mr. Barley was a partner at Greenfield Capital Management, LLC from 1999 to 2004. Mr. Barley earned a Bachelor of Science from Texas Tech University and a Master of Business Administration in Finance from Southern Methodist University.
Patrick J. Welch. Patrick J. Welch has served as the Executive Vice President and Chief Financial Officer of our general partner since April 2014 and served as Interim Chief Financial Officer of our general partner from November 2013 to April 2014. We expect that Mr. Welch will become a member of the board of directors of our general partner prior to the closing of this offering. From August 2013 to April 2014, Mr. Welch served as a Managing Director at Opportune LLP, an independent consultancy focused exclusively on the energy industry. From March 2012 to August 2013, Mr. Welch served as an independent consultant, advising and assisting clients in all aspects of the CFO function in energy companies with a focus on IPO readiness. From June 2011 through March 2012, he served as Chief Financial Officer for RES Americas, a privately held renewable energy development and construction company with activities in the United States and Canada. Mr. Welch served as the Chief Financial Officer of Atlantic Power Corporation (NYSE: AT) from May 2006 through June 2011. Mr. Welch has an extensive background in the energy and independent power industries. Before joining Atlantic Power Corporation, from January 2004 to May 2006, Mr. Welch was Vice President and Controller of DCP Midstream and DCP Midstream Partners, LP (NYSE: DPM) in Denver, Colorado. Prior to that he held various positions at Dynegy Inc. (NYSE: DYN) in Houston, Texas, including Vice President and Controller for Dynegy Generation, and Assistant Corporate Controller. Prior to Dynegy, Mr. Welch was a Senior Audit Manager in the Energy, Utilities and Mining Practice of PricewaterhouseCoopers LLP, predominantly in Houston, Texas, where he served several major energy clients. Mr. Welch earned his Bachelor's Degree from the University of Central Oklahoma and is a Certified Public Accountant.
172
Jeremiah (Jerry) J. Ashcroft III. Jerry Ashcroft has served as the Executive Vice President and Chief Operating Officer of our general partner since April 2014. From January 2012 to April 2014, Mr. Ashcroft was the Senior Vice President of Buckeye GP LLC ("Buckeye") and President, Buckeye Services. Buckeye is the general partner of Buckeye Partners (NYSE: BPL), which owns and operates one of the largest independent liquid petroleum products pipeline systems in the United States. Mr. Ashcroft was the Senior Vice President, Global Operations of Buckeye Pipe Line Services Company ("Services Company") from August 2011 to January 2012. From May 2009 to August 2011, Mr. Ashcroft was Services Company's Vice President, Field Operations. Prior to joining Buckeye, Mr. Ashcroft worked for Colonial Pipeline Company from 2000 to 2006, in roles including Mergers, Acquisitions, and Strategy Coordinator and Control Center Leader, and again from January 2008 to May 2009, first as Chief Compliance Officer and finally as District Leader of Colonial's 2,880-mile southeast region. From November 2006 to January 2008, Mr. Ashcroft served as the General Manager of Georgia Pacific Company's Leaf River Sawmill. Mr. Ashcroft was a decorated Major in the United States Marine Corps and earned his Bachelor's Degree from the United States Naval Academy and his Master of Business Administration from Goizueta Business School, Emory University.
Jon E. Hanna. Jon E. Hanna has served as Executive Vice President—Commercial and Business Development of our general partner since January 2014. Prior to joining JP Energy Partners, Mr. Hanna was Vice President—Business Development of Enable Midstream Partners, a natural gas gathering, processing, transportation and storage partnership, from August 2011 to December 2013. Prior to Enable, Mr. Hanna served as Vice President—Market Development for ONEOK Partners, a natural gas gathering, processing, storage and transportation partnership, from July 2007 to August 2011 and as Vice President—Business Development for ONEOK Hydrocarbon L.P., a NGL processing, storage and transportation partnership, from July 2005 to July 2007. Mr. Hanna held various other positions with ONEOK NGL Marketing, L.P. and ONEOK Energy Marketing from September 2000 to July 2005. Prior to joining ONEOK, Mr. Hanna held positions with Texaco Inc. relating to its NGL and natural gas businesses from November 1989 to September 2000. Mr. Hanna earned a Bachelor of Science in Business Administration from Drake University.
Christopher Hill. Christopher Hill has served as the Senior Vice President—NGL Distribution and Sales of our general partner since January 2011. Mr. Hill co-founded JP Energy Partners and joined as Senior Vice President of Business Development and President of Alliant Gas, LLC in November 2010 and became president of Pinnacle Propane, LLC in January 2012. Prior to joining JP Energy Partners, Mr. Hill was a Vice President of D.H. Investment Co. and Cordillera Ranch Development Corporation from 1999 through October 2010, developing residential and commercial real estate. Mr. Hill earned a Bachelor of Business Administration in Finance at Texas Tech University.
Scott Smith. Scott Smith has served as the Senior Vice President—Crude Oil Supply and Logistics of our general partner since July 2012. Prior to joining JP Energy Partners, Mr. Smith was the Founder, President and Chief Executive Officer of Falco Energy Transportation, LLC, a crude gathering and transportation company, from September 2008 to July 2012. Prior to founding Falco, Mr. Smith served as the Founder, President, and Chief Executive Officer of Falco Energy Marketing, an independent consulting company for crude oil gatherers and transporters from September 2004 to August 2008. Prior to founding Falco Energy Marketing, Mr. Smith served as Director and Vice President of Genesis Crude Oil—Eastern Division, a crude oil gathering and transportation company, from July 1997 to August 2004. Prior to Genesis, Mr. Smith served as the Executive Vice President of Falco S&D Inc., a crude oil gathering and transportation company, from 1990 to 1997. Prior to joining Falco S&D, Mr. Smith served as a Crude Oil Representative for Enron, a crude oil trading and transportation company, from July 1988 to September 1990. Mr. Smith earned a Bachelor's degree in General Business from Louisiana State University.
173
John F. Erhard. John F. Erhard was named a member of the board of directors of our general partner in July 2011 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Erhard, a Partner at ArcLight, joined the firm in 2001 and has 14 years of energy finance and private equity experience. Prior to joining ArcLight, he was an Associate at Blue Chip Venture Company, a venture capital firm focused on the information technology sector. Mr. Erhard began his career at Schroders, where he focused on mergers and acquisitions. Mr. Erhard earned a Bachelor of Arts in Economics from Princeton University and a Juris Doctor from Harvard Law School. Mr. Erhard previously served on the board of directors of Patriot Coal and on the board of directors of Buckeye GP Holdings (NYSE: BGH), the publicly traded general partner of Buckeye Partners (NYSE: BPL). In addition, Mr. Erhard has experience in the master limited partnership sector. He is currently serving on the board of directors of the general partner of American Midstream Partners, L.P. (NYSE: AMID) and previously served on the board of directors of Buckeye GP Holdings. We believe that Mr. Erhard's considerable energy, finance and private equity experience, including his experience with master limited partnerships, provide him with the necessary skills to be a member of the board of directors of our general partner.
Daniel R. Revers. Daniel R. Revers was named a member of the board of directors of our general partner in June 2011 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Revers is Managing Partner of and a co-founder of ArcLight Capital Partners, LLC and has 24 years of energy finance and private equity experience. Mr. Revers manages the Boston office of ArcLight and is responsible for overall investment, asset management, strategic planning, and operations of ArcLight and its funds. Prior to forming ArcLight in 2000, Mr. Revers was a Managing Director in the Corporate Finance Group at John Hancock Financial Services, where he was responsible for the origination, execution, and management of a $6 billion portfolio consisting of debt, equity, and mezzanine investments in the energy industry. Prior to joining John Hancock in 1995, Mr. Revers held various financial positions at Wheelabrator Technologies, Inc., where he specialized in the development, acquisition, and financing of domestic and international power and energy projects. In addition, Mr. Revers is currently serving on the board of directors of the general partner of American Midstream Partners, L.P. (NYSE: AMID). Mr. Revers also serves in various capacities for a number of not-for-profit organizations, currently serving on the Board of Overseers at the Amos Tuck School of Business Administration and the board of directors of the Citizen Schools. Mr. Revers earned a Bachelor of Arts in Economics from Lafayette College and a Master of Business Administration from the Amos Tuck School of Business Administration at Dartmouth College. We believe that Mr. Revers' significant energy, finance and private equity experience provide him with the necessary skills to be a member of the board of directors of our general partner.
Lucius H. Taylor. Lucius H. Taylor was named a member of the board of directors of our general partner in September 2011 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Taylor is a Principal at ArcLight, which he joined in 2007. Mr. Taylor has over 15 years of experience in energy and natural resource finance and engineering. In addition, Mr. Taylor serves on the board of directors of the general partner of American Midstream Partners, L.P. (NYSE: AMID). Prior to joining ArcLight, Mr. Taylor was a Vice President in the Energy and Natural Resource Group at FBR Capital Markets where he focused on raising public and private capital for companies in the power and energy sectors. Mr. Taylor began his career as a geologist and project manager at CH2M HILL, Inc., a global engineering, construction and operations firm. Mr. Taylor earned a Bachelor of Arts in Geology from Colorado College, a Master of Science in Hydrogeology from the University of Nevada, and a Master of Business Administration from the Wharton School at the University of Pennsylvania. Mr. Taylor was selected to serve as a director on the board due to his affiliation with ArcLight, his in-depth knowledge of the energy industry and his financial and business expertise.
174
Greg Arnold. Greg Arnold was named to the board of directors of our general partner in November 2012 and was appointed to the board in connection with the acquisition of our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012. Mr. Arnold has over 25 years of midstream and downstream refined products experience. Mr. Arnold is currently the President, CEO and Chairman of the board of directors of Truman Arnold Companies, a privately owned national petroleum marketing and aviation fixed-based operation company, where he has been since 1987. Mr. Arnold was named President and Chief Operation Officer of Truman Arnold Companies in 1990 and was named President and Chief Executive Officer in 2003. Mr. Arnold has previously served on the board of directors of Century Bancshares, Inc. from 1998 until December of 2008. Additionally, Mr. Arnold served on the board of Christus St. Michael Hospital board prior to 2009. Mr. Arnold received a Bachelor of Business Administration from Stephen F. Austin University. We believe that Mr. Arnold's significant energy industry and financial experience provide him with the necessary skills to be a member of the board of directors of our general partner.
T. Porter Trimble. We expect that T. Porter Trimble will become a member of the board of directors of our general partner prior to the closing of this offering. Mr. Trimble founded Fleur de Lis Energy, L.L.C., a private firm specializing in direct investments in upstream oil and gas assets, in January 2014 and has served as its President since founding. From 2008 until December 2013, Mr. Trimble served as Vice Chairman of Merit Energy Company, a private firm specializing in direct investments in oil and gas assets. Between 2004 and 2008, Mr. Trimble was an Executive Vice President at Merit, in which role he was responsible for the oversight and implementation of Merit's acquisition strategy and the articulation of that strategy to investors. Mr. Trimble has been directly involved in the purchase of over $6.0 billion in oil and gas assets while at Merit and served as a member of its board of directors and its audit committee from 2004 until December 2013. Prior to joining Merit in 1992, Mr. Trimble was with Graham Resources, Inc. in various acquisition and operational positions, and, before that, was in drilling operations for Amoco Production Company in the Gulf of Mexico. Mr. Trimble holds a Bachelor of Science degree in Petroleum Geology from Louisiana State University and a Master of Engineering degree in Petroleum Engineering from Tulane University. We believe that Mr. Trimble's significant energy industry experience, particularly his acquisition strategy and upstream oil and gas expertise, provides him with the necessary skills to be a member of the board of directors of our general partner.
Norman J. Szydlowski. We expect that Norman J. Szydlowski will become a member of the board of directors of our of general partner prior to the closing of this offering. From April 2014 through September 2014, Mr. Szydlowski managed his personal investments as a private investor. Mr. Szydlowski served as president and chief executive officer and Chairman of the board of directors of Rose Rock Midstream GP, LLC from December 2011 to April 2014. Mr. Szydlowski also served as a director and as President and Chief Executive Officer of SemGroup Corporation from November 2009 to April 2014 and as a director of NGL Energy Partners from November 2011 to April 2014. From January 2006 until January 2009, Mr. Szydlowski served as president and chief executive officer of Colonial Pipeline Company, an interstate common carrier of petroleum products. From 2004 to 2005, he served as a senior consultant to the Iraqi Ministry of Oil in Baghdad on behalf of the U.S. Department of Defense, where he led an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served as vice president of refining for Chevron Corporation (formerly ChevronTexaco), one of the world's largest integrated energy companies. Mr. Szydlowski joined Chevron in 1981 and served in various capacities of increasing responsibility in sales, planning, supply chain management, refining and plant operations, transportation and construction engineering.
175
The chief executive officer of our general partner currently serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by the members of our general partner, including Lonestar and certain members of management. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
Compensation Discussion and Analysis
We do not directly employ any of the persons responsible for managing our business. Our general partner, under the direction of its board of directors, is responsible for managing our operations and employs all of the employees that operate our business. The compensation payable to the officers of our general partner is paid by our general partner and such payments are reimbursed by us. For more information please read "Our Partnership Agreement—Reimbursement of Expenses." However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this Compensation Discussion and Analysis.
This Compensation Discussion and Analysis provides an overview and analysis of (i) the elements of our compensation program for our named executive officers, or NEOs, identified below, (ii) the material compensation decisions made under that program and reflected in the executive compensation tables that follow this Compensation Discussion and Analysis and (iii) the material factors considered in making those decisions. Our general partner intends to provide our NEOs with compensation that is significantly performance based. Our executive compensation program is designed to align executive pay with our performance on both short and long-term bases, link executive pay to the creation of value for unitholders and utilize compensation as a tool to assist us in attracting and retaining the high-caliber executives that we believe are critical to our long-term success.
176
Compensation for our executive officers consists primarily of the elements, and their corresponding objectives, identified in the following table.
Compensation Element
|
Primary Objective | |
|---|---|---|
Base salary |
Recognize performance of job responsibilities and attract and retain individuals with superior talent. | |
Annual performance-based compensation |
Promote near-term performance and reward individual contributions to our business on an annual basis. | |
Discretionary long-term equity incentive awards |
Emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership and value creation in our partnership. | |
Retirement savings (401(k)) plan |
Provide an opportunity for tax-efficient savings and long term financial security. |
|
Other elements of compensation and perquisites |
Attract and retain talented executives in a cost-efficient manner by providing benefits with high perceived values at relatively low cost. |
To serve the foregoing objectives, our overall executive compensation program is generally designed to be flexible rather than formulaic. Our compensation decisions for our NEOs in fiscal 2013 are discussed below in relation to each of the above-described elements of our compensation program. The below discussion is intended to be read in conjunction with the executive compensation tables and related disclosures that follow this Compensation Discussion and Analysis.
For the year ended December 31, 2013, our NEOs were:
- •
- J. Patrick Barley, our Chairman, President and Chief Executive Officer;
- •
- Patrick Welch, our Executive Vice President and Chief Financial Officer
- •
- Christopher Hill, our Senior Vice President—NGL Distribution and Sales;
- •
- Scott Smith, our Senior Vice President—Crude Oil Supply and Logistics; and
- •
- Todd Whitbeck, our former Senior Vice President and Chief Financial Officer.
Our overall compensation program is structured to attract, motivate and retain highly qualified executive officers by paying them competitively, consistent with our success and their contribution to that success. We believe compensation should be structured to ensure that a significant portion of compensation opportunity will be related to factors that directly and indirectly influence unitholder value. Consistent with our performance-based philosophy, we provide a base salary to our NEOs and significant incentive-based compensation opportunity, which includes variable awards under our annual incentive bonus program.
Although our general partner has not historically made annual grants of equity-based awards as a means of compensating our executives, we have from time to time made grants of common units in us to our NEOs, primarily in connection with their commencement of employment with us and our
177
affiliates. Our NEOs also hold and have received awards of equity interests in affiliates of our general partner, as described in more detail under the heading "Certain Relationships and Related Party Transactions—Equity Interests in Affiliates of our General Partner." Although no equity or equity-based awards were granted to our NEOs in 2013, we believe that equity participation by our NEOs is an important component of NEO pay. As a result, in anticipation of this offering we intend to adopt a new long-term equity incentive plan, the 2014 Long-Term Incentive Plan, under which we will make grants of equity and equity-based awards to align our NEOs' interests with our long-term performance. This plan is discussed in more detail under "2014 Long-Term Incentive Plan" below.
The compensation committee of the board of directors of our general partner, or the Compensation Committee, is provided with the primary authority to determine and approve the compensation awards available to our NEOs and is charged with reviewing our executive compensation policies and practices to ensure (i) adherence to our compensation philosophies and (ii) that the total compensation paid to our NEOs is fair, reasonable and competitive, taking into account our position within our industry and the level of expertise and experience of our NEOs in their positions. As a result, the Compensation Committee periodically (i) reviews each NEO's base salary, (ii) assesses the performance of the Chief Executive Officer and other NEOs for each applicable performance period and (iii) determines the amount of awards to be paid to our Chief Executive Officer and other NEOs under our annual bonus incentive program for each year. In making compensation and performance determinations for our NEOs other than our CEO, the Compensation Committee will consider, and the Board has historically followed, the recommendations of our CEO. Additionally, on a historical basis, performance determinations for our NEOs have been made in a subjective and discretionary manner without regard to pre-determined financial, operational or other performance goals or metrics. However, in the future, we expect that the Compensation Committee may establish annual incentive programs that include the consideration of objective performance-based goals or metrics.
In determining compensation levels for our NEOs, our general partner has historically considered each NEO's unique position and responsibility and relies upon the judgment and industry experience of its members, including their knowledge of competitive compensation levels in our industry and, beginning in 2013, the analysis and advice provided to the Compensation Committee by an independent compensation consultant, as described in more detail below under the heading "—Role of the Compensation Consultant and Peer Group Analysis." We believe that our NEOs' base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace and adjusted for financial and operating performance and previous work experience. In this regard, each NEO's current and prior compensation, including compensation paid by the NEO's prior employer, is considered as a reference point against which determinations are made as to whether increases are appropriate to retain the NEO in light of competition or in order to provide continuing performance incentives.
Role of Compensation Consultant and Peer Group Analysis
The Compensation Committee's charter will authorize the Committee to retain independent compensation consultants from time to time to serve as a resource in support of its efforts to carry out certain duties. In 2013, the Compensation Committee engaged Mercer, an independent compensation consultant, to assist the Committee in assessing and structuring competitive compensation packages for the executive officers that are consistent with our compensation philosophy.
At the request of our board of directors, Mercer reviewed and provided input on the compensation of our NEOs, trends in executive compensation, meeting materials prepared for and circulated to our board of directors and management's proposed executive compensation plans. Mercer also developed assessments of market levels of compensation through an analysis of peer data and
178
information disclosed in our peer companies' public filings, but did not determine or recommend specific amounts or forms of compensation.
The peer group used for this market analysis in 2013 consisted of the following 20 companies in the energy industry: Buckeye Partners, Western Gas Partners, Regency Energy Partners, Genesis Energy, MPLX LP, Suburban Propane Partners, Tesoro Logistics, PVR Partners, Holly Energy Partners, Atlas Pipeline Partners, Oiltanking Partners, Ferrellgas Partners, Crosstex Energy, Summit Midstream Partners, Crestwood Midstream Partners, Marlin Midstream Partners, Rose Rock Midstream, Delek Logistics Partners, TransMontaigne Partners and Blueknight Energy Partners. These companies were selected as the compensation peer group for any or all of the following reasons:
- (i)
- they
reflect our industry competitors for products and services;
- (ii)
- they
operate in similar markets or have comparable geographical reach;
- (iii)
- they
are of similar size and maturity to us; or
- (iv)
- they are companies that have similar credit profiles and comparable growth or capital programs to us.
The Compensation Committee reviews the peer group annually and may, from time to time, add or remove companies in order to assure the composition of the group meets the criteria outlined above.
The information that Mercer compiled included compensation trends for MLPs and levels of compensation for similarly-situated executive officers of companies within this peer group. We believe that compensation levels of executive officers in our peer group are relevant to our compensation decisions because we compete with those companies for executive management talent. While the Compensation Committee considers the compensation levels of peer group executives when making compensation determinations, it does not benchmark salaries or other compensation levels against any specific compensation levels of peer group executives. In general, Mercer's analysis indicated that base salaries for our NEOs were slightly above the 25th percentile, on average, for similarly situated executives at our peer group companies. However, there was wide variation by NEO position. The Compensation Committee considered these relative pay levels when making base salary adjustments for our NEOs following review of the Mercer analysis, as discussed below.
We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions with similar responsibilities in our marketplace. Base salaries for our NEOs were initially set at modest levels, primarily due to our limited operating history at the time such salaries were determined, with the expectation that base salaries would be increased over time to bring them closer to competitive levels of base salaries in our industry. As a result, in early 2013, we implemented base salary increases for each of our NEOs, as set forth in the table below. These increases were made in contemplation of our becoming a public company, to reflect the increased complexity and scope of our business as it has grown since 2010 and to establish appropriate relative pay levels for our NEOs to reflect each NEO's level of authority and responsibility within our organization. In addition, following the Compensation Committee's review of the Mercer analysis, which is discussed above, the Compensation Committee determined to provide additional salary
179
increases for our NEOs, as set forth in the table below under the heading "Current Base Salary." These increases were made into better align our NEOs pay with competitive levels in our industry.
Name and Principal Position
|
Prior Base Salary($) |
Base Salary Following Initial 2013 Increase($) |
Current Base Salary(1)($) |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
J. Patrick Barley |
250,000 | 400,000 | 425,000 | |||||||
Chairman, President and Chief Executive Officer |
||||||||||
Patrick Welch |
— |
(2) |
— |
(2) |
400,000 |
|||||
Executive Vice President and Chief Financial Officer |
||||||||||
Christopher Hill |
200,000 |
275,000 |
325,000 |
|||||||
Senior Vice President—NGL Distribution and Sales |
||||||||||
Scott Smith |
300,000 |
300,000 |
325,000 |
|||||||
Senior Vice President—Crude Oil Supply and Logistics |
||||||||||
Todd Whitbeck |
375,000 |
375,000 |
— |
(3) |
||||||
Former Senior Vice President and Chief Financial Officer |
||||||||||
- (1)
- Represents
current base salary, which became effective as of July 1, 2013.
- (2)
- Mr. Welch
served as an outside consultant and in that role acted as our principal financial officer from November 2013 to April 2014 pursuant to a
consulting agreement that we entered into with Opportune LLP, a third party service provider that employed Mr. Welch during that time. Mr. Welch became an employee of our general partner
with the title of Executive Vice President and Chief Financial Officer in April 2014. Mr. Welch's base salary and other compensation items were established based on an arms-length negotiation
with him upon his commencement of employment.
- (3)
- Mr. Whitbeck left the employ of the company and ceased to be an executive officer on November 1, 2013.
In the future, base salaries, along with other elements of compensation, will be reviewed and may be adjusted periodically by the Compensation Committee.
We structure our compensation programs to reward executive officers based on our performance and the individual executive's relative contribution to that performance. Each of our NEOs participates in our annual bonus program, under which cash incentive awards are determined annually in the discretion of the board of directors of our general partner. In making individual annual bonus decisions, the board of directors of our general partner has not historically relied on pre-determined performance goals or targets and did not do so for 2013. Instead, determinations regarding annual bonus compensation awards have been based on a subjective assessment of all reasonably available information, including the applicable executive's business impact, contributions and leadership, among other factors. For 2013, throughout the year, our NEOs demonstrated sustained commitment and leadership through the execution of our business development strategies as well as the implementation of significant organizational initiatives in connection with the preparation of this offering. However, our financial performance generally fell below expectations. Therefore, while we determined to pay bonuses to our NEOs at a meaningful level in recognition of their contributions to our business in 2013, bonus payouts were generally at a level below bonus amounts that were paid to our executives in prior years. Based upon these considerations, the percentage of salary awarded as bonuses to each of our NEOs for
180
2013 was as follows: Mr. Barley: 68%; Mr. Hill: 66%; and Mr. Smith: 21%. Mr. Whitbeck and Mr. Welch were not eligible for any annual incentive bonus for 2013. In determining individual award levels, the board of directors of our general partner generally considered on a subjective basis each NEO's level of authority and responsibility within our organization and their corresponding contributions to our successes for 2013.
Our NEOs are eligible under the same plans as all other employees for medical and dental coverage and life and other insurance. We provide these benefits due to their relatively low cost and the high value they provide in attracting and retaining talented executives. Our NEOs do not receive any tax gross up in connection with our provision of these benefits. In addition, for 2013, we provided certain perquisites to Mr. Welch in the form of temporary living, housing and commuting expenses, primarily related to his long-distance commuting requirements from his personal residence in Colorado to our executive offices. Mr. Welch receives a tax gross up in connection with the provision of his housing and commuting expenses. Our general partner is continuing to provide similar payments and benefits to Mr. Welch pursuant to an employment offer letter agreement entered into with Mr. Welch in connection with his commencement of long-term employment with us in April 2014.
Our general partner considers the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their "at-will" employment with us may result in the departure or distraction of management personnel to our detriment. Accordingly, with respect to our NEOs, our general partner has entered or is entering in connection with this offering into employment agreements with each of Mr. Welch and Mr. Smith to encourage the continued attention and dedication of these members of our management and to allow them to focus on the value to unitholders of strategic alternatives without concern for the impact on their continued employment.
Agreement with Mr. Welch. In anticipation of this offering, our general partner is entering into an employment agreement with Mr. Welch, which will have a three-year initial term and are subject to automatic annual renewal thereafter unless either party gives the other a notice of non-extension at least 60 days prior to the expiration of the then-applicable term. The agreements provide for an annual base salary in amounts consistent with the executives' current base salary as described above, subject to review and adjustment from time to time. In addition, the agreements provide for the executives to participate in the bonus and benefit plans maintained by our general partner from time to time. If our general partner terminates the executive's employment for cause or due to death or disability or if the executive resigns his employment without good reason, then he will receive only his base salary earned through the date of termination but not yet paid, any expenses owed to him and any amount accrued arising from his participation in employee benefit plans or as required by law and, solely in the event of a termination of employment due to disability or death, continued payment of the executive's base salary through the end of the third or first month, respectively, following termination. Any further right to salary, bonus or other benefits will cease. However, if the executive's employment is terminated by our general partner without cause or he resigns for good reason during the term of the employment agreement and, in either case, signs a release of claims in favor of our general partner, then he will be entitled to receive, as severance payments, an amount equal to one year of the executive's base salary plus an amount equal to the average of the executive's annual bonus received during the three most recent fiscal years (or if the executive was not employed with our general partner over the full three most recent fiscal years, his target bonus will substituted for the year in which he was not employed for purposes of determining the average bonus), plus an amount equal to the executive's healthcare continuation COBRA premiums for twelve months. The executive would also receive company-paid
181
COBRA premiums. If such termination occurs within six months after a change in control of us or our general partner, severance amount would be two times the executive's base salary and bonus amount and the healthcare continuation period would be 24 months.
In addition, upon termination of employment, the employment agreement for Mr. Welch provides that he (i) will not engage in any business that is competitive with us in the geographical locations where we operate for a period of at least 12 months following termination and (ii) will not solicit our employees, customers, suppliers or other business associates for a period of two years following termination.
For purposes of the employment agreements described above, "Cause" is defined generally as (i) fraud, embezzlement or theft against us or our general partner or a material violation of company policies, (ii) gross negligence, dishonesty or fraud causing material harm to us or our general partner or any conviction of, or guilty plea or nolo contendere plea to, or confession of, a Class A-type felony or felony involving moral turpitude or other crime involving moral turpitude, (iii) unauthorized disclosure or misuse of our confidential information, (iv) material nonperformance of duties, willful misconduct or breach of fiduciary duty that is not cured within 10 days after notice to the executive thereof, (v) use of illegal drugs at work, or (vi) a material breach of the employment agreement. "Good reason" is defined generally as (i) a material and adverse diminution in job title or duties, (ii) a material breach of our general partner's obligations under the agreement (including a failure to pay or provide salary or benefits), (iii) a greater than 50 mile relocation of the executive's primary place of employment, or (iv) a material reduction in the executive's base salary (generally requiring a 10% or greater reduction), in each case that is not cured within 30 days of the executive's objection thereto.
Agreement with Mr. Smith. Our general partner entered into an employment agreement with Mr. Smith in July 2012, which provides for an initial term of twelve months following the date of the agreement. If our general partner terminates Mr. Smith's employment for cause or due to death or disability or if he resigns his employment without good reason, then he will receive only his base salary earned through the date of termination but not yet paid, any expenses owed to him, any amount accrued arising from his participation in employee benefit plans or as required by law, and, solely in the event of a termination of employment due to disability, continued payment of his base salary through the end of the second month following termination. Any further right to salary, bonus, or other benefits will cease. However, if Mr. Smith's employment is terminated by our general partner without cause or he resigns for good reason and, in either case, signs a release of claims in favor of our general partner, then he will be entitled to receive, as severance payments, an amount of cash payable in a lump sum equal to six months of his base salary plus an amount equal to the base salary he would have received for the remainder of the initial twelve month term of the agreement. Because the initial twelve month term of the agreement ended in July 2013, if Mr. Smith's employment is terminated in these circumstances he would receive only six months of base salary.
For purposes of Mr. Smith's employment agreement, "Cause" is defined generally in a manner consistent with the agreement for Mr. Welch and "Good reason" is defined generally as (i) a material and adverse diminution in job title or duties, (ii) a material breach of our general partner's obligations under the agreement (including a failure to pay or provide salary or benefits), or (iii) a greater than 50 mile relocation of the executive's primary place of employment, in each case that is not cured within 30 days of the executive's objection thereto
Agreements with Mr. Whitbeck. Our general partner entered into an employment agreement with Mr. Whitbeck, effective as of October 5, 2011, for a term of three years from such date. Mr. Whitbeck's employment with our general partner terminated in November 2013. In connection with his termination of employment, pursuant to the terms of his employment agreement, our general partner provided Mr. Whitbeck with a severance payment equal to thirteen months of his then current
182
base salary, along with continued healthcare and other benefits coverage under our general partner's welfare benefit plans on terms consistent with other active employees.
Summary Compensation Table for 2013
The following table sets forth certain information with respect to the compensation paid to our NEOs for the year ended December 31, 2013.
Name and Principal Position
|
Year | Salary($) | Bonus($)(1) | Unit Awards($) |
All Other Compensation($)(2) |
Total($) | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
J. Patrick Barley |
2013 | 405,769 | 276,250 | — | 4,577 | 686,596 | |||||||||||||
President and Chief Executive Officer |
2012 | 240,385 | 510,000 | — | — | 750,385 | |||||||||||||
Patrick Welch(3) |
2013 |
127,200 |
— |
— |
20,580 |
147,780 |
|||||||||||||
Executive Vice President and Chief Financial Officer |
|||||||||||||||||||
Christopher Hill |
2013 |
295,192 |
195,000 |
— |
— |
490,192 |
|||||||||||||
Senior Vice President—NGL Distribution and Sales |
2012 | 192,308 | 158,750 | — | — | 351,058 | |||||||||||||
Scott Smith |
2013 |
311,538 |
65,000 |
— |
11,269 |
387,807 |
|||||||||||||
Senior Vice President—Crude Oil Supply and Logistics |
|||||||||||||||||||
Todd Whitbeck |
2013 |
328,846 |
— |
— |
407,610 |
736,456 |
|||||||||||||
Former Senior Vice President and Chief Financial Officer |
2012 | 288,462 | 360,000 | 208,100 | — | 856,562 | |||||||||||||
- (1)
- The
2013 bonus amounts reflect bonuses paid in early 2014 that relate to services performed in 2013 and represent the awards earned under our annual
incentive bonus program. For additional information, please read "—Annual Performance-Based Compensation for 2013" above.
- (2)
- For
Mr. Whitbeck, the 2013 amount shown includes a severance payment of $406,250 following the termination of his employment and $1,360 representing
benefits continuation amounts for the remainder of Mr. Whitbeck's severance period. For Mr. Barley and Mr. Smith, the amount shown reflects company contributions to our 401(k)
retirement savings plan. Neither Mr. Hill nor Mr. Whitbeck participated in our 401(k) retirement savings plan in 2012 or 2013.
- (3)
- Mr. Welch served as an outside consultant and was functionally our Chief Financial Officer from November 2013 to April 2014 pursuant to a consulting agreement that we entered into with Opportune LLP. The compensation in the table above reflects $127,200 of fees paid to the consulting firm that employed Mr. Welch for his services to us in 2013, $7,072 for temporary housing and living assistance including lodging expenses, $12,293 for travel and commuting expenses, including ground transportation and airfare costs.
Grants of Plan-Based Awards for 2013
None of our NEOs received any grants of plan based awards during the year ended December 31, 2013.
Outstanding Equity Awards at December 31, 2013
None of our NEOs held any option awards or unvested unit awards in us that were outstanding as of December 31, 2013.
183
Options Exercised and Units Vested in 2013
The following table sets forth the number and value of class B common unit awards in us that vested for the NEOs during 2012. Only Mr. Whitbeck held any equity or equity-based awards in us that vested during 2013 and all unvested awards held by him as of the date of his termination of employment in October 2013 were forfeited.
| |
Unit Awards | ||||||
|---|---|---|---|---|---|---|---|
Name
|
Number of Units Acquired on Vesting (#) |
Value Realized on Vesting ($)(1) |
|||||
J. Patrick Barley |
— | — | |||||
Patrick Welch |
— | — | |||||
Christopher Hill |
— | — | |||||
Scott Smith |
— | — | |||||
Todd Whitbeck |
2,000 | 42,520 | |||||
- (1)
- The amount shown reflects an estimate of the fair market value of the units as of the date of vesting of October 5, 2013, as determined by our general partner.
Nonqualified Deferred Compensation and Pension Benefits
None of our NEOs participate in any nonqualified deferred compensation plans or pension plans and received no nonqualified deferred compensation or pension benefits during the year ended December 31, 2013.
Potential Payments upon Termination or Change in Control
Upon the consummation of this offering, each of Messrs. Welch and Smith will have an agreement that provides for severance benefits upon a termination of employment. See "—Employment Agreements" above for a description of the employment and severance agreements for each of our NEOs. Assuming that each of these agreements were in place on December 31, 2013, as applicable, and a termination of employment effective as of December 31, 2013 (i) by our general partner without
184
cause, (ii) due to the executive's resignation for good reason or (iii) due to the executive's disability, each of our NEOs would have received the following payments and benefits:
Name
|
Payment Type |
Termination Without Cause or Resignation for Good Reason($) |
Death($) | Termination due to Disability($) |
Termination Without Cause or Resignation for Good Reason After a Change in Control($) |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
J. Patrick Barley |
Salary | n/a | n/a | n/a | n/a | ||||||||||
|
Bonus | n/a | n/a | n/a | n/a | ||||||||||
|
Total | n/a | n/a | n/a | n/a | ||||||||||
Patrick Welch |
Salary |
417,921 |
(1) |
33,333 |
99,999 |
835,842 |
(1) |
||||||||
|
Bonus | 300,000 | — | — | 600,000 | ||||||||||
|
Total | 717,921 | 33,333 | 99,999 | 1,435,842 | ||||||||||
Christopher Hill |
Salary |
n/a |
n/a |
n/a |
n/a |
||||||||||
|
Bonus | n/a | n/a | n/a | n/a | ||||||||||
|
Total | n/a | n/a | n/a | n/a | ||||||||||
Scott Smith |
Salary |
162,500 |
162,500 |
54,167 |
— |
||||||||||
|
Total | 162,500 | 162,500 | 54,167 | — | ||||||||||
- (1)
- Salary amount shown includes an estimated amount for healthcare continuation COBRA reimbursement payments of $17,921 per year.
Mr. Whitbeck's employment with our general partner terminated in November 2013. The amount of the severance payments and benefits paid, provided and to be provided to Mr. Whitbeck in connection with his termination of employment is included in the Summary Compensation Table above under the column headed "All Other Compensation."
2014 Long-Term Incentive Plan
Our general partner intends to adopt the JP Energy Partners LP 2014 Long-Term Incentive Plan, or the LTIP, for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the LTIP, which awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under the LTIP and all determinations with respect to awards to be made under the LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. 3,642,700 common units will be reserved for issuance, pursuant to and in accordance with the LTIP. The following description reflects the terms that are currently expected to be included in the LTIP.
General. The LTIP will provide for the grant, from time to time at the discretion of the board of directors or compensation committee of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards
185
under the LTIP is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.
Restricted units and phantom units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.
Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.
Distribution equivalent rights. The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.
Unit options and unit appreciation rights. The administrator of the LTIP, in its discretion, may also permit the grant of unit options or unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.
Unit awards. Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.
Profits interest units. Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.
Other unit-based awards. The administrator of the LTIP may also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of any other unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, any other unit-based award may be paid in cash
186
and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.
Source of common units. Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.
Certain transactions. The administrator of the LTIP will have broad discretion to equitably adjust the provisions of the LTIP and the terms and conditions of existing and future awards, including with respect to the aggregate number and type of units subject to the LTIP and awards granted pursuant to the LTIP, to prevent the dilution or enlargement of intended benefits and/or facilitate necessary or desirable changes in the event of certain transactions and events affecting our units, such as unit splits, mergers, acquisitions, consolidations and other extraordinary transactions. In the case of certain events or changes in capitalization that could result in additional compensation expense to us or our general partner if adjustments to awards with respect to such event were discretionary, then equitable adjustments will be non-discretionary. The administrator of the LTIP may also provide for the acceleration, cash-out, termination, assumption, substitution or conversion of awards in the event of certain unusual or nonrecurring events or transactions.
Amendment or termination of LTIP. The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.
Compensation Risk
We have analyzed the potential risks arising from our compensation policies and practices, and have determined that there are no such risks that are reasonably likely to have a material adverse effect on us.
For the year ended December 31, 2013, our NEOs or other employees who also served as members of the board of directors of our general partner did not receive additional compensation for their service as directors. Additionally, directors who were not officers, employees or paid consultants or advisors of us or our general partner did not receive compensation for their services as directors. Following the consummation of this offering, officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as directors. Following the consummation of this offering, our directors who are not officers, employees or paid consultants or advisors of us or our general partner or its affiliates will receive cash and equity-based compensation for their services as directors. Although the terms of our expected director compensation program have not yet been determined, we expect such compensation may consist of the following:
- •
- an annual retainer of $50,000;
- •
- an additional annual retainer of $10,000 for service as the chair of any standing committee and a $5,000 fee for service
on two or more committees;
- •
- meeting attendance fees of $1,750 per meeting attended, whether telephonically or in person; and
- •
- with respect to the first year following the closing of this offering, an equity-based award of 2,000 phantom or restricted units granted under the LTIP and vesting in one-third increments on each of the first three anniversaries of the grant date.
We also expect to grant additional equity based awards annually to our directors on terms that have not yet been determined. Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officer liability insurance coverage. Under our partnership agreement, each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law, subject to certain limitations provided in our partnership agreement.
187
SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units of JP Energy Partners LP that will be issued upon the consummation of this offering and the related transactions and held by beneficial owners of 5.0% or more of the units, by each director and director nominee of JP Energy GP II LLC, our general partner, by each named executive officer and by all directors, director nominees and officers of our general partner as a group and assumes no exercise of the underwriters' option to purchase additional common units.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of September 22, 2014, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
The following table does not include any common units that directors and executive officers may purchase in this offering through the directed unit program described under "Underwriting." The percentage of units beneficially owned is based on a total of 18,213,502 common units and 18,213,502 subordinated units outstanding immediately following this offering.
Name of Beneficial Owner(1)
|
Common Units to be Beneficially Owned |
Percentage of Common Units to be Beneficially Owned |
Subordinated Units to be Beneficially Owned |
Percentage of Subordinated Units to be Beneficially Owned |
Percentage of Total Common Units and Subordinated Units to be Beneficially Owned |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Lonestar Midstream Holdings, LLC |
3,667,305 | 20.1 | % | 14,964,588 | 82.2 | % | 51.1 | % | ||||||||
Directors/Named Executive Officers: |
||||||||||||||||
J. Patrick Barley(2) |
30,663 | * | 125,122 | * | * | |||||||||||
Patrick J. Welch |
— | — | — | — | — | |||||||||||
Jeremiah J. Ashcroft III |
2,190 | * | 8,937 | * | * | |||||||||||
Jon E. Hanna |
— | — | — | — | — | |||||||||||
Christopher Hill |
2,303 | * | 9,398 | * | * | |||||||||||
Scott Smith(3) |
19,469 | * | 79,443 | * | * | |||||||||||
John F. Erhard(4) |
— | — | — | — | — | |||||||||||
Daniel R. Revers(4) |
— | — | — | — | — | |||||||||||
Lucius H. Taylor(4) |
— | — | — | — | — | |||||||||||
Greg Arnold(5) |
290,244 | 1.6 | % | 1,184,352 | 6.5 | % | 4.0 | % | ||||||||
Director Nominees: |
||||||||||||||||
T. Porter Trimble |
— | — | — | — | — | |||||||||||
Norman J. Szydlowski |
||||||||||||||||
All directors, director nominees and executive officers as a group (12 persons) |
344,869 |
1.9 |
% |
1,407,252 |
7.7 |
% |
4.8 |
% |
||||||||
- (1)
- Unless
otherwise indicated, the address for all beneficial owners in this table is 600 East Las Colinas Boulevard, Suite 2000, Irving, Texas
75039.
- (2)
- J. Patrick Barley owns and controls substantially all of each of JP Energy GP LLC and CB Capital Holdings II, LLC. Each of JP Energy GP LLC and CB Capital Holdings II, LLC is a member of Lonestar
188
Midstream Holdings, LLC ("Lonestar") but neither has any investment or voting control over the units held by Lonestar and therefore Mr. Barley disclaims beneficial ownership of the units held by Lonestar. Mr. Barley owns and controls 100% of JP Energy Holdings, LLC, which will own 30,663 of our common units and 125,122 of our subordinated units upon the closing of this offering.
- (3)
- Mr. Smith
owns and controls 100% of Falco Crude Services, LLC, which will own 19,469 common units and 79,443 subordinated units upon the
closing of this offering.
- (4)
- ArcLight
Energy Partners Fund V, L.P. ("ArcLight Fund V") owns and controls, through one of its wholly owned subsidiaries, Lonestar and
therefore may be deemed to indirectly beneficially own the 3,667,305 common units and 14,964,588 subordinated units that will be held directly by Lonestar upon the closing of this offering.
Messrs. Revers, Erhard and Taylor, each a director of our general partner, are managing partner, partner and principal, respectively, of ArcLight Capital Partners, LLC. ArcLight Capital
Parners, LLC is the investment manager of, and ArcLight Capital Holdings, LLC is the managing partner of the general partner of, ArcLight Fund V. The investment committee of
ArcLight Capital Partners, LLC generally exercises voting and dispositive power over the units held by Lonestar, with the committee consisting of six members including Messrs. Revers and
Erhard. Messrs. Erhard and Taylor do not have beneficial ownership of the units held by Lonestar. Due to certain voting rights granted to Mr. Revers as a member of ArcLight Capital
Partners, LLC's investment committee, he may be deemed to indirectly beneficially own the units held by Lonestar, but disclaims any such ownership except to the extent of his pecuniary interest
therein. The address for each of Messrs. Revers, Erhard, and Taylor is 200 Clarendon Street, 55th Floor, Boston, MA 02116.
- (5)
- Mr. Arnold indirectly owns 100% of Arkansas Terminaling & Trading, Inc, which will own 290,244 of our common units and 1,184,352 of our subordinated units upon the closing of this offering. The address for Mr. Arnold is 100 Crescent Ct., Suite 1600, Dallas, Texas 75201.
189
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
After this offering, our general partner and its affiliates, including Lonestar, will own 4,025,754 common units and 16,427,252 subordinated units representing a 56.2% limited partner interest in us (or 2,165,529 common units and 16,427,252 subordinated units, representing a 51.0% limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, our general partner will own a non-economic general partner interest in us and all of our incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of JP Energy Partners LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Formation Stage
| The consideration received by our general partner and its affiliates prior to or in connection with this offering |
• 4,025,754 common units |
|
|
• 16,427,252 subordinated units; |
|
|
• a non-economic general partner interest; |
|
|
• the incentive distribution rights; |
|
|
• the right to receive their pro rata share of the approximately $92.1 million in accounts receivable that comprise our gross working capital to be distributed to our existing unitholders; and |
|
|
• the right to have up to 1,860,225 common units redeemed with the proceeds of any exercise of the underwriters' option to purchase additional common units. |
Operational Stage
| Distributions of available cash to our general partner and its affiliates |
We will generally make cash distributions of 100.0% to the unitholders pro rata, including Lonestar, as holder of an aggregate of 4,025,754 common units and 16,427,252 subordinated units. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level. Our general partner will not receive distributions on its non-economic general partner interest. |
190
| Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $26.6 million on their common units and subordinated units. | ||
Payments to our general partner and its affiliates |
Our general partner will not receive a management fee or other compensation for its management of us. However, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. |
|
Withdrawal or removal of our general partner |
If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "Our Partnership Agreement—Withdrawal or Removal of Our General Partner." |
Liquidation Stage
| Liquidation | Upon our liquidation, the partners will be entitled to receive liquidating distributions according to their respective capital account balances. |
Agreements With Affiliates in Connection With the Transactions
We and other parties have entered into or will enter into the various agreements that will affect the transactions. While not the result of arm's-length negotiations, we believe the terms of all of our initial agreements will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions, will be paid for with the proceeds of this offering.
Right of First Offer Agreement
We and our general partner will enter into a Right of First Offer Agreement (the "ROFO agreement") with JP Development and an affiliate of ArcLight Fund V ("ArcLight Fund V") at the closing of this offering. The ROFO agreement will contain the terms and conditions upon which (i) JP Development will grant us a right of first offer with respect to all of the current and future assets of JP Development and its subsidiaries (each, a "Development entity") and (ii) ArcLight Fund V will grant us a right of first offer with respect to a 50% indirect interest in Republic (clauses (i) and (ii) are collectively referred to as the "ROFO Assets"). The ROFO agreement will have a primary term of five
191
years with respect to the current and future assets of JP Development and will have a primary term of eighteen months with respect to the 50% indirect interest in Republic. The ROFO Agreement may be extended for subsequent annual periods by written agreement prior to its expiration.
The ROFO agreement's right of first offer will provide that if any Development entity or ArcLight Fund V proposes to transfer any ROFO Asset to a non-affiliated third party, then such Development entity or ArcLight Fund V, as the case may be, must give us notice of its intent to make a transfer and include in the notice the material terms and conditions of the transfer. Following receipt of the notice, we will have (x) 60 days (for notices delivered by Development) or (y) 30 days (for notices delivered by ArcLight Fund V) to propose an offer which will contain the terms on which we propose to acquire the ROFO Asset that is the subject of the proposed transfer. Our offer will be subject to approval by the conflicts committee of the board of directors of our general partner. If we do not propose an offer within such 60-day or 30-day period, as applicable, we will be deemed to have waived our right of first offer with respect to the proposed transfer of the subject ROFO Asset. If we propose an offer within the specified time period, we and JP Development or ArcLight Fund V, as applicable, will be required to engage in good faith negotiations for up to 30 days with respect to the terms and conditions upon which the subject ROFO Asset will be sold to us. If we and JP Development or ArcLight Fund V, as the case may be, are unable to agree to the terms of a purchase and sale of the subject ROFO Asset within such 30 day period, the Development entity or ArcLight Fund V, as the case may be, will be permitted to transfer the subject ROFO Asset to a third party (i) on terms no more favorable to such third party than those set forth in the last written offer proposed by us during negotiations between us and JP Development pursuant to the ROFO Agreement and (ii) at a price equal to no less than 100% of the price offered by us in such last written offer.
Other Transactions With Related Persons
Purchase Agreements With Lonestar
In July 2012, we and JP Development separately entered into purchase agreements with Lonestar under which Lonestar committed to make capital contributions of $300 million (including contributions already made) through the purchase of equity interests in us and JP Development to fund our and JP Development's business and operations. On October 7, 2013, we terminated our purchase agreement with Lonestar.
Series D Subscription Agreement
On March 28, 2014, we issued 1,818,182 Series D Convertible Preferred Units (the "Series D Preferred Units") to Lonestar for a cash purchase price of $22.00 per Series D Preferred Unit pursuant to the terms of a subscription agreement by and among us, our general partner and Lonestar. This transaction resulted in proceeds to us of approximately $40 million, which are to be used for growth capital expenditures.
JP Development
We perform certain general and administrative services for JP Development pursuant to a services agreement in exchange for a monthly fee of $50,000, which fee is subject to adjustment each month to accurately reflect the degree and extent of the services provided. For the year ended December 31, 2013, we received $600,000 of fees from JP Development. During 2013, we also incurred certain expenses on behalf of JP Development and its subsidiary entities which were cash settled on a monthly basis. In addition, JP Development periodically advanced us cash, in the form of prepayments, for these expenses.
JP Development owned a pipeline transportation business that provided crude oil pipeline transportation services to our crude oil supply and logistics segment. We purchased the pipeline
192
transportation business from JP Development in February 2014. Due to the recasting of our financial statements following our acquisition of JP Development's pipeline transportation business, we are considered to have utilized JP Development's pipeline transportation services during the year ended December 31, 2013, resulting in pipeline tariff fees of $16,944,000.
On November 5, 2013, we issued a $1.0 million promissory note to JP Development in order to raise funds for working capital requirements which we repaid in full on March 20, 2014. On July 18, 2013, we issued 45,860 Class C common units to JP Development for total net proceeds of $1,628,000. On August 13, 2013, we issued 42,254 Class C common units to JP Development for total net proceeds of $1,500,000.
Refined Products Sale Agreements
We have entered into two refined products sale agreements (the "refined products sale agreements") with Truman Arnold Companies ("TAC"). TAC will directly or indirectly own a 4.0% limited partner interest in us at the close of this offering. Each of the refined products sale agreements provides that we will sell and deliver to TAC certain refined petroleum products at agreed upon prices and in amounts that we and TAC may agree to from time to time. Each of the refined products sale agreements contains certain other customary terms and provisions. Each of the refined products sale agreements is effective as of November 27, 2012, had an initial term that expired on January 1, 2013 and will continue on a month-to-month basis unless terminated by either party upon 30 days' notice. The parties have agreed to terminate the agreements as of August 31, 2014. For the year ended December 31, 2013 and the six months ended June 30, 2014, the revenue generated from the refined products sales agreements was $14,473,000 and $8,380,000, respectively. In addition to the refined products sale agreements, our NGL distribution and sales segment purchased refined products from TAC during the year ended December 31, 2013. We paid TAC $187,000 for such products.
Lonestar Registration Rights Agreement
We entered into a registration rights agreement with Lonestar in June 2011 (the "Lonestar registration rights agreement") under which we agreed to (i) use commercially reasonable efforts to prepare and file with the SEC a shelf registration statement within 120 days of the closing of this offering to permit the resale of the common units held by Lonestar and (ii) use commercially reasonable efforts to cause such shelf registration statement to become effective no later than 180 days after it is filed. Additionally, at any time after the closing of this offering, in the event that we file a registration statement of any kind for the sale of common units for our own account or the account of another person or if any holder of registrable securities notifies us that it seeks to dispose of such registrable securities in an underwritten offering, we must notify Lonestar and offer it the opportunity to include its common units in such filing or underwritten offering. Under certain circumstances, we are entitled to delay rights under which we may, upon written notice to any selling holder, suspend such holder's use of a prospectus under a registration statement for a period not to exceed an aggregate of 60 days in any 180-day period or an aggregate of 90 days in any 365-day period. Although we are responsible for all expenses incurred in connection with the filing of any registration statement under the Lonestar registration rights agreement, any holder seeking to sell registrable securities thereunder must pay its own legal expenses and underwriting fees, discounts or commissions allocable to the sale of such securities. The Lonestar registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses and the registration rights which it grants are subject to certain conditions and limitations. All registrable securities held by Lonestar and any permitted transferee will be entitled to these registration rights. We and Lonestar will terminate this agreement at the completion of this offering. Lonestar will be entitled to enforce the registration rights provisions set forth in our partnership agreement.
193
Terminal Registration Rights Agreement
In connection with the acquisition of our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012, we entered into a registration rights agreement (the "Terminal registration rights agreement") with certain of the sellers (the "Terminal Sellers") where we agreed to grant "piggyback" rights. Pursuant to the terms of the piggyback rights, at any time after the closing of this offering, in the event that we file a registration statement of any kind for the sale of common units for our own account or the account of another person or if any holder of registrable securities notifies us that it seeks to dispose of such registrable securities in an underwritten offering, we must notify the Terminal Sellers and offer them the opportunity to include their common units in such filing or underwritten offering. In addition, at any time after we become eligible to register our securities on Form S-3 under the Securities Act of 1933, as amended (the "Securities Act"), any one or more of the Terminal Sellers that is a holder of registrable securities is entitled to certain demand rights, whereby they may request that we register such securities for sale under the Securities Act. These demand rights may be exercised on up to two occasions. We are entitled to select the managing underwriter for any registration of securities under the Terminal registration rights agreement. Although we are responsible for all expenses incurred in connection with the filing of any registration statement, any holder seeking to sell registrable securities under the Terminal registration rights agreement must pay certain selling expenses, including underwriting fees, discounts or commissions allocable to the sale of such securities. The Terminal registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses and the registration rights which it grants are subject to certain conditions and limitations. All registrable securities held by the Terminal Sellers and any permitted transferee will be entitled to these registration rights.
Equity Interests in Affiliates of Our General Partner
Mr. Barley and Mr. Hill hold certain equity interests, which they have purchased from time to time, in JP Energy GP LLC and CB Capital Holdings II, LLC, which each hold membership interests in our general partner and in JP Development. In addition, in September 2012 and February 2014, Mr. Barley and Mr. Hill each received grants of additional equity interests in JP Energy GP LLC and CB Capital Holdings II, LLC. Mr. Barley and Mr. Hill paid no consideration for these interests, which were intended to constitute "profits interests" under applicable IRS guidance. The interests granted to Mr. Barley and Mr. Hill were 100% vested upon grant.
Employees of Our General Partner
We ceased having employees in July 2013. Since July 2013, the employees supporting our operations are employees of our general partner and, as such, we reimburse our general partner for our payroll and other payroll-related expenses that it incurs on our behalf.
CAMS Bluewire Technology, LLC
CAMS Bluewire Technology, LLC ("CAMS Bluewire"), an entity in which ArcLight holds a non-controlling interest, provides us with IT support. For the year ended December 31, 2013 and the six months ended June 30, 2014, we paid CAMS Bluewire $691,000 and $216,000, respectively, for IT support and consulting services.
Supply and Logistics Agreement with Republic
Subject to entering into definitive documentation, we have agreed to provide Republic with certain commercial and business development services. We expect to design crude oil solutions for producers from the wellhead to the end market.
194
Procedures for Review, Approval and Ratification of Related Person Transactions
We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.
Please read "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest" for additional information regarding the relevant provisions of our partnership agreement.
The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.
195
CONFLICTS OF INTEREST AND DUTIES
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Lonestar, JP Development and ArcLight, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner that is in the best interests of its owners. At the same time, our general partner has a duty to manage us in a manner that it believes is in the best interests of our partnership.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee on a case-by-case basis. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, the board of directors of our general partner will consider a variety of factors, including the nature of the conflict of interest, the size of the transaction and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek special approval or unitholder approval. Whenever our general partner makes a determination to seek special approval, to seek unitholder approval or to adopt a resolution or course of action that has not received special approval or unitholder approval, then our general partner will be entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such action free of any duty or obligation whatsoever to our partnership or any limited partner, and our general partner will not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity, and our general partner in making such determination or taking or declining to take such action will be permitted to do so in its sole and absolute discretion. For a more detailed discussion of the duties applicable to our general partner, please read "—Duties of the General Partner." An independent third party is not required to evaluate the fairness of the resolution.
Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution or course of action in respect of such conflict is:
- •
- approved by the conflicts committee, although our general partner is not obligated to seek such approval; or
- •
- approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates.
If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
If our general partner does not seek approval from the conflicts committee or unitholder approval and our general partner's board of directors takes or declines to take a course of action with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will
196
have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner's board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is in the best interests of the partnership. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. Please read "Management—Management of JP Energy Partners LP—Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.
It is possible, but we believe it is unlikely, that our general partner would approve a matter that the conflicts committee has previously declined to approve or declined to recommend that the full board of directors approve. If the conflicts committee does not approve or does not recommend that the full board of directors approve a matter that has been presented to it, then, unless the board of directors of our general partner has delegated exclusive authority to the conflicts committee, the board of directors of our general partner may subsequently approve the matter. In such a case, although the matter will not have received "special approval" under our partnership agreement, the board of directors of our general partner could still determine to resolve the conflict of interest solely under the good faith standard. In making any such determination, the board of directors of our general partner may take into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Please read "—Management Committees of the Board of Directors—Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.
Conflicts of interest could arise in the situations described below, among others.
Affiliates of our general partner, including Lonestar, JP Development and ArcLight, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Lonestar, JP Development and ArcLight, are not prohibited from engaging in other businesses or activities, including those that might directly compete with us. Neither our partnership agreement nor our omnibus agreement will prohibit our sponsor or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, Lonestar, JP Development and ArcLight. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Lonestar, JP Development and ArcLight may compete with us for acquisition opportunities and may own an interest in entities that directly compete with us.
197
Our general partner is allowed to take into account the interests of parties other than us, such as Lonestar, JP Development and ArcLight, in resolving conflicts of interest.
Our partnership agreement contains provisions that reduce and modify the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duty or obligation to us and our unitholders when acting in its individual capacity, our general partner is entitled to consider only the interests and factors that it desires, and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right, its voting rights with respect to the units it owns and its registration rights, its determination whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement and whether to refer or not to refer any potential conflict of interest to the conflicts committee for special approval or to seek or not to seek unitholder approval.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, and limits our general partner's liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.
In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:
- •
- permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors
affecting, us or any limited partner. Examples of decisions that our general partner may make in its individual capacity include: (i) how to allocate business opportunities among us and its
other affiliates; (ii) whether to exercise its limited call right; (iii) how to exercise its voting rights with respect to the units it owns; (iv) whether to exercise its
registration rights; (v) whether to elect to reset target distribution levels; and (vi) whether or not to consent to any merger or consolidation of the partnership or amendment to our
partnership agreement;
- •
- provides that our general partner will have no liability to us or our limited partners for decisions made in its capacity
as a general partner so long as such decisions are made in good faith;
- •
- generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any
determination by our general partner must be made in good faith; if an affiliate transaction or the resolution of another conflict of interest does not receive special approval or unitholder approval,
then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be
subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or
at equity; under our partnership agreement, it will be presumed that in making its decision our general partner (including the board of directors of our general partner) acted in good faith, and in
any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption;
and
- •
- provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a
198
final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the case may be, acted in bad faith or engaged in actual fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.
By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
- •
- the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting
for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;
- •
- the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights,
warrants and appreciation rights relating to our securities;
- •
- the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
- •
- the negotiation, execution and performance of any contracts, conveyances or other instruments;
- •
- the distribution of our cash;
- •
- the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of employment or hiring;
- •
- the maintenance of insurance for our benefit and the benefit of our partners;
- •
- the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any
limited or general partnership, joint venture, corporation, limited liability company or other entity;
- •
- the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or
in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;
- •
- the indemnification of any person against liabilities and contingencies to the extent permitted by law;
- •
- the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other
agencies having jurisdiction over our business or assets; and
- •
- the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf in its capacity as our general partner, and our partnership agreement further provides that in order for a determination to be made in "good faith," our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the
199
totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. When our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. Please read "Our Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.
Actions taken by our general partner may affect the amount of distributable cash flow available for distribution to unitholders or accelerate the right to convert subordinated units.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
- •
- the amount and timing of asset purchases and sales;
- •
- cash expenditures;
- •
- borrowings;
- •
- the issuance of additional units; and
- •
- the creation, reduction or increase of reserves in any quarter.
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.
In addition, our general partner may use an amount, initially equal to $30.0 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
- •
- enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the
incentive distribution rights; or
- •
- accelerating the expiration of the subordination period.
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow working capital funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period."
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.
We will reimburse our general partner and its affiliates for expenses.
We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services
200
provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read "Certain Relationships and Related Party Transactions."
Contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm's-length negotiations.
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the close of this offering. While neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations, we believe the terms of all of our initial agreements with our general partner and its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.
Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.
Common units are subject to our general partner's limited call right.
Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read "Our Partnership Agreement—Limited Call Right."
Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or our conflicts committee and may perform services for our general
201
partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of our conflicts committee or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50.0%) for each of the prior four consecutive calendar quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Furthermore, our general partner has the right to transfer all or any portion of the incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two calendar quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights."
The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action.
As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that might otherwise be owed by our general partner with contractual
202
standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has duties to manage our general partner in a manner that is in the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:
| State law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership. |
203
| Partnership agreement standards | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith," meaning that it subjectively believed that the decision was in the best interests of our partnership, and will not be subject to any higher standard under our partnership agreement or applicable law. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. These contractual standards reduce the obligations to which our general partner would otherwise be held. | |
If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. |
||
If our general partner does not seek special approval from our conflicts committee or unitholder approval, then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. |
204
| In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. | ||
Rights and remedies of unitholders |
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement. |
By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions of our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "Our Partnership Agreement—Indemnification."
205
DESCRIPTION OF THE COMMON UNITS
The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "Our Partnership Agreement."
Duties
American Stock Transfer & Trust Company, LLC will serve as the registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:
- •
- surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in
connection therewith;
- •
- special charges for services requested by a holder of a common unit; and
- •
- other similar fees or charges.
There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
Resignation or Removal
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:
- •
- automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership
agreement;
- •
- represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership
agreement; and
- •
- gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with this offering.
206
Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Common units are securities and transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
207
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
- •
- with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash
Distributions";
- •
- with regard to the duties of our general partner, please read "Conflicts of Interest and Duties";
- •
- with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common
Units"; and
- •
- with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."
Our partnership was organized on May 5, 2010 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.
Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the businesses in which we are currently engaged, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."
The following is a summary of the unitholder vote required for the matters specified below. Matters that require the approval of a "unit majority" require:
- •
- during the subordination period, the approval of a majority of the outstanding common units, excluding those common units
held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and
- •
- after the subordination period, the approval of a majority of the outstanding common units.
208
In voting their common units and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.
| Issuance of additional units | No approval rights. | |
Amendment of our partnership agreement |
Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of Our Partnership Agreement." |
|
Merger of our partnership or the sale of all or substantially all of our assets |
Unit majority. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets." |
|
Dissolution of our partnership |
Unit majority. Please read "—Termination and Dissolution." |
|
Continuation of our business upon dissolution |
Unit majority. Please read "—Termination and Dissolution." |
|
Withdrawal of the general partner |
Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to December 31, 2024 in a manner which would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner." |
|
Removal of the general partner |
Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner." |
|
Transfer of the general partner interest |
Our general partner may transfer all, but not less than all, of its non-economic general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2024. Please read "—Transfer of General Partner Interest." |
|
Transfer of incentive distribution rights |
Our general partner may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read "—Transfer of Incentive Distribution Rights." |
209
| Reset of incentive distribution levels | No approval right. | |
Transfer of ownership interests in our general partner |
No approval right. Please read "—Transfer of Ownership Interests in Our General Partner." |
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
- •
- to remove or replace our general partner;
- •
- to approve some amendments to our partnership agreement; or
- •
- to take other action under our partnership agreement;
constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.
Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating companies may require compliance with legal requirements in the jurisdictions in which our operating companies conducts business, including qualifying our subsidiaries to do business there.
Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interests in our operating subsidiaries or otherwise, it were determined that we were
210
conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.
Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.
Amendment of Our Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
211
Prohibited Amendments
No amendment may be made that would:
- •
- enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of
an amendment approved by at least a majority of the type or class of limited partner interests so affected; or
- •
- enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.
The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the completion of this offering, our general partner and its affiliates will own approximately 56.1% of the outstanding common and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner under our directed unit program).
No Unitholder Approval
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
- •
- a change in our name, the location of our principal office, our registered agent or our registered office;
- •
- the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
- •
- a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a
limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an
association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
- •
- an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors,
officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted
under the Employee Retirement Income Security Act of 1974 (ERISA), whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of
Labor;
- •
- an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of
additional partnership interests;
- •
- any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
- •
- an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our
partnership agreement;
- •
- any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;
212
- •
- a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or
appropriate as a result of such change;
- •
- mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets,
liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or
- •
- any other amendments substantially similar to any of the matters described in the clauses above.
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:
- •
- do not adversely affect in any material respect the limited partners considered as a whole or any particular class of
partnership interests as compared to other classes of partnership interests;
- •
- are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
- •
- are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule,
regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;
- •
- are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under
the provisions of our partnership agreement; or
- •
- are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
Opinion of Counsel and Unitholder Approval
For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain such an opinion of counsel.
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90.0% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets
A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or
213
the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20.0% of our outstanding partnership interests immediately prior to the transaction.
If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:
- •
- the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner
other than by reason of a transfer of its non-economic general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of
a successor;
- •
- the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
- •
- the entry of a decree of judicial dissolution of our partnership; or
- •
- there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.
Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
- •
- the action would not result in the loss of limited liability of any limited partner; and
- •
- neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
214
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
Withdrawal or Removal of Our General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2024 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2024 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' written notice to the limited partners if at least 50.0% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its non-economic general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."
Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read "—Termination and Dissolution."
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner's removal. At the closing of this offering, our general partner and its affiliates will own 56.1% of the outstanding common and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner under our directed unit program).
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
- •
- the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a
one-for-one basis;
- •
- any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
215
- •
- our general partner will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.
In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interest
Except for transfer by our general partner of all, but not less than all, of its general partner interest to (i) an affiliate of our general partner (other than an individual), or (ii) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general partner interest to another person prior to December 31, 2024 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
Transfer of Ownership Interests in Our General Partner
At any time, the owners of our general partner, including Lonestar, may sell or transfer all or part of their membership interest in our general partner to an affiliate or third party without the approval of our unitholders.
Transfer of Incentive Distribution Rights
At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.
216
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove JP Energy GP II LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates or any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Withdrawal or Removal of Our General Partner."
If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days' written notice.
The purchase price in the event of this purchase is the greater of:
- •
- the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of
the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
- •
- the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.
As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."
Redemption of Ineligible Holders
In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by FERC or an analogous regulatory body, our general partner at any time can request a transferee or a unitholder to certify or re-certify:
- •
- that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the
income generated by us; or
- •
- that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity's owners are subject to United States federal income taxation on the income generated by us.
Furthermore, in order to avoid a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest as the result of any federal, state or local law or regulation concerning the nationality, citizenship or other related status of any unitholder, our general partner may at any time request unitholders to certify as to, or provide other information with respect to, their nationality, citizenship or other related status.
217
The certifications as to taxpayer status and nationality, citizenship or other related status can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.
If a unitholder fails to furnish the certification or other requested information within 30 days or if our general partner determines, with the advice of counsel, upon review of such certification or other information that a unitholder does not meet the status set forth in the certification, we will have the right to redeem all of the units held by such unitholder at the market price as of the date three days before the date the notice of redemption is mailed.
The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.
Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. The general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.
Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class. Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
218
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
- •
- our general partner;
- •
- any departing general partner;
- •
- any person who is or was an affiliate of our general partner or any departing general partner;
- •
- any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our
subsidiaries, or any entity set forth in the preceding three bullet points;
- •
- any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of
another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates; and
- •
- any person designated by our general partner because such person's status, service or relationship expose such person to claims or suits relating to our business and affairs.
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, our fiscal year is the calendar year.
We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 50 days after the close of each quarter.
219
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.
Right to Inspect Our Books and Records
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:
- •
- a current list of the name and last known address of each record holder;
- •
- copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and
- •
- certain information regarding the status of our business and financial condition.
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of JP Energy GP II LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."
Our partnership agreement will provide that the Court of Chancery of the State of Delaware shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner's, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies' certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.
220
UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold an aggregate of 4,025,754 common units and 16,427,252 subordinated units (or 2,165,529 common units and 16,427,252 subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. All of the common units and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act other than any units purchased in this offering by directors, director nominees and executive officers of our general partner. Directors, director nominees and executive officers of our general partner may purchase common units through the directed unit program or otherwise. Assuming all of the units reserved for issuance under the directed unit program are sold to directors, director nominees and executive officers of our general partner, common units will be held by persons who have contractually agreed not to sell such units for a specified period from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions. Additionally, any common units owned by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
- •
- 1.0% of the total number of the common units outstanding, which will equal approximately 182,135 units immediately after
this offering; or
- •
- the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.
At the closing of this offering, the following common units will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act, Rule 144 or otherwise:
- •
- common units owned by our general partner and its affiliates; and
- •
- any units acquired by our general partner or any of its affiliates, including the directors, director nominees and executive officers of our general partner under the directed unit program.
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.
Our Partnership Agreement and Registration Rights
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or
221
other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "Our Partnership Agreement—Issuance of Additional Securities."
Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.
We, our subsidiaries, our general partner and its affiliates, including Lonestar, and the directors, director nominees and executive officers of our general partner have agreed that without the prior written consent of each of Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, we and they will not, directly or indirectly, sell any common units which we or they beneficially own for a period of 180 days after the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.
Registration Statement on Form S-8
We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under the LTIP. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.
222
MATERIAL FEDERAL INCOME TAX CONSEQUENCES
This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to JP Energy Partners LP and our operating subsidiaries.
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, entities treated as partnerships for United States federal income tax purposes, trusts, nonresident aliens, United States expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-United States persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, United States persons whose "functional currency" is not the United States dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.
No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in distributable cash flow available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.
For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read
223
"—Disposition of Common Units—Allocations Between Transferors and Transferees") and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90.0% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof, including the retail and wholesale marketing of propane and natural gas liquids, and certain related hedging activities. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 6.0% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90.0% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes. Instead, we will rely on the opinion of Latham & Watkins LLP on such matter. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:
- •
- we will be classified as a partnership for federal income tax purposes; and
- •
- each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.
In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:
- •
- neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation;
- •
- for each taxable year, more than 90.0% of our gross income has been and will be income of the type that Latham &
Watkins LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code; and
- •
- each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified pursuant to applicable Treasury Regulations.
We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS
224
may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.
Unitholders of JP Energy Partners LP will be treated as partners of JP Energy Partners LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of JP Energy Partners LP for federal income tax purposes.
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."
Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences of holding common units in JP Energy Partners LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in JP Energy Partners LP for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-Through of Taxable Income
Subject to the discussion below under "—Tax Consequences of Unit Ownership—Entity-Level Collections" we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
225
Treatment of Distributions
Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses."
A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.
Ratio of Taxable Income to Distributions
We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2017, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.
The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:
- •
- gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only
distribute the minimum quarterly distributions on all units; or
- •
- we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such
226
as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.
Basis of Common Units
A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will generally have a share of our nonrecourse liabilities based on his share of our profits. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Limitations on Deductibility of Losses
The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in other publicly traded partnerships, or the unitholder's salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an
227
unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
Limitations on Interest Deductions
The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:
- •
- interest on indebtedness properly allocable to property held for investment;
- •
- our interest expense attributed to portfolio income; and
- •
- the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.
Entity-Level Collections
If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of the intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction
In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated to the unitholders in accordance with their percentage interests in us.
Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering (including any difference attributable to partnership asset revaluations arising from previously-existing
228
built-in tax gain) and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates (or by a third party) that exists at the time of such contribution, together referred to in this discussion as the "Contributed Property." The effect of these allocations to a unitholder purchasing common units from us in this offering, referred to as "reverse Section 704(c) Allocations" and "Section 704(c) Allocations," respectively, will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, additional reverse Section 704(c) Allocations will be made to all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, both with respect to this offering and any future offering, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
- •
- his relative contributions to us;
- •
- the interests of all the partners in profits and losses;
- •
- the interest of all the partners in cash flow; and
- •
- the rights of all the partners to distributions of capital upon liquidation.
Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.
Treatment of Short Sales
A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
- •
- any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
- •
- any cash distributions received by the unitholder as to those units would be fully taxable; and
- •
- while not entirely free from doubt, all of these distributions would appear to be ordinary income.
229
Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."
Alternative Minimum Tax
Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26.0% on the first $182,500 of alternative minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
Tax Rates
Under current law, the highest marginal United States federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal United States federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20.0%. Such rates are subject to change by new legislation at any time.
In addition, a 3.8% Medicare tax, or NIIT, is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income and (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (a) undistributed net investment income and (b) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. The Department of the Treasury and the IRS issued Treasury Regulations that provide guidance regarding the NIIT. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.
Section 754 Election
We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.
230
We have adopted the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150.0% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.
231
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
Accounting Method and Taxable Year
We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."
Initial Tax Basis, Depreciation and Amortization
The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our partners holding interests in us prior to this offering, and (ii) any other offering will be borne by our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."
To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."
The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
232
Valuation and Tax Basis of Our Properties
The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the United States federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to NIIT in certain circumstances. Please read "—Tax Consequences of Unit Ownership—Tax Rates."
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or
233
low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
- •
- a short sale;
- •
- an offsetting notional principal contract; or
- •
- a futures or forward contract;
in each case, with respect to the partnership interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees
In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated
234
items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.
Notification Requirements
A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.
Constructive Termination
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets.
235
Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-United States person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30.0%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "United States net equity," that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
A foreign unitholder who sells or otherwise disposes of a common unit will be subject to United States federal income tax on gain realized from the sale or disposition of that unit to the extent the
236
gain is effectively connected with a United States trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the United States by virtue of the United States activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect United States trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to United States federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5.0% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50.0% or more of the fair market value of all of our assets consisted of United States real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50.0% of our assets consist of United States real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.
Information Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1.0% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.0% interest in profits or by any group of unitholders having in the aggregate at least a 5.0% interest in profits. However, only one
237
action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
Additional Withholding Requirements
Withholding taxes may apply to certain types of payments made to "foreign financial institutions" (as specially defined in the Internal Revenue Code) and certain other non-United States entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States ("FDAP Income"), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States ("Gross Proceeds") paid to a foreign financial institution or to a "non-financial foreign entity" (as specially defined in the Internal Revenue Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial United States owners or furnishes identifying information regarding each substantial United States owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the United States Treasury requiring, among other things, that it undertake to identify accounts held by certain United States persons or United States-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders.
These rules generally will apply to payments of FDAP Income made on or after July 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a United States trade or business (please read "—Tax-Exempt Organizations and Other Investors"), unitholders who are foreign financial institutions or certain other non-United States entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.
Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.
Nominee Reporting
Persons who hold an interest in us as a nominee for another person are required to furnish to us:
- •
- the name, address and taxpayer identification number of the beneficial owner and the nominee;
- •
- whether the beneficial owner is:
- (1)
- a
person that is not a United States person;
- (2)
- a
foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
- (3)
- a
tax-exempt entity;
- •
- the amount and description of units held, acquired or transferred for the beneficial owner; and
238
- •
- specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.
Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
Accuracy-Related Penalties
An additional tax equal to 20.0% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10.0% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
- •
- for which there is, or was, "substantial authority"; or
- •
- as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150.0% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200.0% or more (or 50.0% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10.0% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200.0% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40.0%. We do not anticipate making any valuation misstatements.
In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40.0%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.
239
Reportable Transactions
If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Administrative Matters—Information Returns and Audit Procedures."
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:
- •
- accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than
described above at "—Administrative Matters—Accuracy-Related Penalties";
- •
- for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
- •
- in the case of a listed transaction, an extended statute of limitations.
We do not expect to engage in any "reportable transactions."
Recent Legislative Developments
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read "—Partnership Status". We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
State, Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in every state in the continental United States. Many of these states impose an income tax on corporations and other entities. Many of these states also impose a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a
240
percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.
241
INVESTMENT IN JP ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-United States or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, "Similar Laws." For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements, collectively, "Employee Benefit Plans." Among other things, consideration should be given to:
- •
- whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
- •
- whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of
ERISA and any other applicable Similar Laws;
- •
- whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the
potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and
- •
- whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.
The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the Employee Benefit Plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.
The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:
(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;
242
(b) the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or
(c) there is no significant investment by "benefit plan investors," which is defined to mean that less than 25.0% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.
Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above. The foregoing discussion of issues arising for employee benefit plan investments under ERISA and the Internal Revenue Code is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.
243
Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC and Deutsche Bank Securities Inc. are acting as the representatives of the underwriters and the joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:
Underwriters
|
Number of Common Units |
|||
|---|---|---|---|---|
Barclays Capital Inc. |
||||
Merrill Lynch, Pierce, Fenner & Smith |
||||
RBC Capital Markets, LLC |
||||
Deutsche Bank Securities Inc. |
||||
BMO Capital Markets Corp. |
||||
Robert W. Baird & Co. Incorporated |
||||
Simmons & Company International |
||||
Stephens Inc. |
||||
Janney Montgomery Scott LLC |
||||
Total |
13,750,000 | |||
The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:
- •
- the obligation to purchase all of the common units offered hereby (other than those common units covered by their option
to purchase additional common units as described below), if any of the common units are purchased;
- •
- the representations and warranties made by us to the underwriters are true;
- •
- there is no material change in our business or the financial markets; and
- •
- we deliver customary closing documents to the underwriters.
The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.
| |
No Exercise | Full Exercise | |||||
|---|---|---|---|---|---|---|---|
Per common unit |
$ | $ | |||||
Total |
$ | $ | |||||
We will pay a structuring fee equal to 0.50% of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated for the evaluation, analysis and structuring of our partnership.
The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to
244
selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters.
The expenses of the offering that are payable by us are estimated to be $2.0 million (excluding underwriting discounts and commissions and structuring fees).
Option to Purchase Additional Common Units
We have granted the underwriters an option, exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of 2,062,500 additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 13,750,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.
We, our subsidiaries, our general partner and its affiliates, including Lonestar, and the directors, director nominees and executive officers of our general partner, have agreed that without the prior written consent of each of Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, we and they will not, directly or indirectly, (i) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (ii) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (iii) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or (iv) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.
These restrictions do not apply to, among other things:
- •
- the sale of common units pursuant to the underwriting agreement;
- •
- issuances of common units by us pursuant to any employee benefit plan in effect as of the date of the underwriting
agreement provided that such common units will be subject to the 180-day restricted period; and
- •
- the filing of one or more registration statements on Form S-8 relating to any employee benefit plan in effect as of the date of the underwriting agreement.
Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.
245
As described below under "Directed Unit Program," any common units sold in the Directed Unit Program to the directors, director nominees or officers of our general partner shall be subject to the lock-up agreement described above.
Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:
- •
- the history and prospects for the industry in which we compete,
- •
- our financial information,
- •
- the ability of our management and our business potential and earning prospects;
- •
- the prevailing securities markets at the time of this offering; and
- •
- the recent market prices of, and the demand for, publicly-traded common units of generally comparable companies.
We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the Directed Unit Program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.
At our request, the underwriters have reserved for sale at the initial public offering price up to 5.0% of the common units offered hereby for officers, directors, director nominees, employees and certain other persons associated with us and our general partner. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any common units sold in the directed unit program to the directors, director nominees and executive officers of our general partner will be subject to the 180-day lock-up agreements described above.
Stabilization, Short Positions and Penalty Bids
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act.
- •
- Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a
specified maximum.
- •
- A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase
246
- •
- Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been
completed in order to cover syndicate short positions.
- •
- Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
We have been approved to list our common units on the New York Stock Exchange under the symbol "JPEP." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange listing requirements for trading.
247
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.
If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
Certain of the underwriters and/or their affiliates have in the past and may in the future perform investment banking, commercial banking, advisory and other services for us and our affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.
In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.
Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Deutsche Bank Securities Inc. and BMO Capital Markets Corp. are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds from this offering.
Because the Financial Industry Regulatory Authority, Inc. ("FINRA"), views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
European Economic Area
This prospectus has been prepared on the basis that the transactions contemplated by this prospectus in any Member State of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State") (other than Germany) will be made pursuant to an exemption under the Prospectus Directive from the requirement to publish a prospectus for offers of securities. Accordingly, any person making or intending to make any offer in that Relevant Member State of the securities which are the subject of the transactions contemplated by this prospectus, may only do so in circumstances in which no obligation arises for us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive in relation to such offer. Neither we nor any of the underwriters have authorized, nor do they authorize, the making of any offer of securities or any invitation relating thereto in circumstances in which an obligation arises for us or any of the underwriters to publish a prospectus for such offer or invitation.
248
In relation to each Relevant Member State, other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date"), no offer to the public of the securities subject to this supplement has been or will be made in that Relevant Member State other than:
- (a)
- to
any legal entity which is a qualified investor as defined in the Prospectus Directive ("Qualified Investors");
- (b)
- to
fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons
(other than Qualified Investors), as permitted under the Prospectus Directive subject to obtaining our prior consent for any such offer; or
- (c)
- in any other circumstances falling within Article 3(2) of the Prospectus Directive,
provided that no such offer or invitation shall require us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
For the purposes of this provision, the expression an "offer to the public" means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase the securities, as the same may be further defined in that Relevant Member State by any measure implementing the Prospectus Directive in that Member State. The expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State, and the expression "2010 Amending Directive" means Directive 2010/73/EU.
We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.
United Kingdom
We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000 ("FSMA") that is not a "recognised collective investment scheme" for the purposes of FSMA ("CIS") and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and are only directed at (i) investment professionals falling within the description of persons in Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the "CIS Promotion Order") or Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the "Financial Promotion Order") or (ii) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order or Article 49(2)(a) to (d) of the Financial Promotion Order, or (iii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). Our common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.
249
Switzerland
The distribution of our common units in Switzerland will be exclusively made to, and directed at, regulated qualified investors ("Regulated Qualified Investors"), as defined in Article 10(3)(a) and (b) of the Swiss Collective Investment Schemes Act of 23 June 2006, as amended ("CISA"). Accordingly, we have not, and will not be, registered with the Swiss Financial Market Supervisory Authority ("FINMA") and no Swiss representative or paying agent has been or will be appointed for us in Switzerland. This prospectus and/or any other offering materials relating to our common units may be made available in Switzerland solely to Regulated Qualified Investors.
Germany
This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Asset Investment Act (Vermögensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1 in connection with Section 2 no. 6 of the German Securities Prospectus Act, Section 2 no. 4 of the German Asset Investment Act, and in Section 2 paragraph 11 sentence 2 no.1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.
The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.
Netherlands
Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).
Hong Kong
Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong Kong (Cap. 571, Laws of Hong Kong) ("SFO") and any rules made under the SFO or (b) in other circumstances which do not result in this prospectus being deemed to be a "prospectus," as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong) ("CO"), or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to our common units which are or are intended to be disposed of only to persons outside Hong Kong or only to professional investors as defined in the SFO.
250
The validity of our common units will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas and Washington, D.C.
The consolidated financial statements of JP Energy Partners LP as of December 31, 2013 and December 31, 2012 and for each of the three years in the period ended December 31, 2013 included in this prospectus have been so included in reliance on the report (which contains an explanatory paragraph relating to the Partnership's restatement of its financial statements as described in Note 3 to the financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
The consolidated financial statements of Falco Energy Transportation, LLC as of July 19, 2012 and December 31, 2011 and for the period from January 1, 2012 to July 19, 2012 and for the year ended December 31, 2011 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
The financial statements of Heritage Propane Express, LLC as of June 6, 2012 and December 31, 2011 and for the period from January 1, 2012 to June 6, 2012 and the year ended December 31, 2011, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.
The financial statements of Parnon Storage Inc. as of March 31, 2011 and 2012, and for each of the years in the three-year period ended March 31, 2012, have been included herein in reliance upon the report of Travis Wolff, LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in auditing and accounting.
The combined financial statements of Caddo Mills Pipeline Terminal of Truman Arnold Companies and Arkansas Terminaling and Trading, Inc. as of and for the year ended December 31, 2011, and as of and for the period from January 1, 2012 through November 27, 2012, have been included herein in reliance upon the report of Travis Wolff, LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in auditing and accounting.
The statements of Revenues and Direct Operating Expenses of the Crude Oil Supply and Logistics Business of Parnon Gathering, Inc. for the seven months ended July 31, 2012 and the year ended December 31, 2011, have been included herein in reliance upon the report of Travis Wolff, LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in auditing and accounting.
The statements of operations and cash flows of Wildcat Permian Services, LLC for the periods from September 12, 2012 (inception) through December 31, 2012 and from January 1, 2013 to October 6, 2013 have been included herein in reliance upon the report of Hein & Associates LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in auditing and accounting.
251
On August 8, 2012, we retained PricewaterhouseCoopers LLP as our independent registered public accounting firm. Our previous independent accounting firm was Weaver and Tidwell, L.L.P. The decision to dismiss Weaver and Tidwell, L.L.P. and appoint PricewaterhouseCoopers LLP was approved by our general partner's board of directors on August 8, 2012.
The reports of Weaver and Tidwell, L.L.P. on our consolidated financial statements for each of the two fiscal years prior to its dismissal did not contain any adverse opinion or disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principles. We had no disagreements with Weaver and Tidwell, L.L.P. on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to its satisfaction, would have caused Weaver and Tidwell, L.L.P. to make reference in connection with its opinion to the subject matter of the disagreement during its audits for each of the two fiscal years prior to its dismissal or the subsequent interim period through August 8, 2012. During the two most recent fiscal years preceding Weaver and Tidwell, L.L.P.'s dismissal, and the subsequent interim period through August 8, 2012, there were no "reportable events" as such term is defined in Item 304(a)(1)(v) of Regulation S-K.
During the two years ended December 31, 2011 and through the period ended August 8, 2012, we did not consult with PricewaterhouseCoopers LLP on matters that involved the application of accounting principles to a specified transaction, either completed or proposed, the type of audit opinion that might be rendered on our financial statements or any other matter that was the subject of a disagreement as that term is used in Item 304 (a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K or a reportable event as that term is used in Item 304(a)(1)(v) and the related instructions to Item 304 of Regulation S-K.
We have provided Weaver and Tidwell, L.L.P. with a copy of the foregoing disclosure and have requested that Weaver and Tidwell, L.L.P. furnish us with a letter addressed to the SEC stating whether or not Weaver and Tidwell, L.L.P. agrees with the above statements and, if not, stating the respects in which it does not agree. A copy of the letter from Weaver and Tidwell, L.L.P. is filed as an exhibit to the registration statement of which this prospectus is a part.
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.
The SEC maintains a website on the internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.
Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website on the Internet is located at www.jpenergypartners.com and we will make our periodic reports
252
and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.
253
F-1
F-2
JP ENERGY PARTNERS LP
UNAUDITED PRO FORMA COMBINED CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma combined consolidated financial statements consist of JP Energy Partners LP's (the "Partnership," "JPE," "us," "we," or "our") unaudited pro forma combined consolidated statements of operations for the six months ended June 30, 2014 and for the year ended December 31, 2013, and an unaudited pro forma combined consolidated balance sheet as of June 30, 2014. The unaudited pro forma combined consolidated financial statements have been derived by application of pro forma adjustments to our historical financial statements included elsewhere in this prospectus.
The unaudited pro forma combined consolidated statement of operations for the six months ended June 30, 2014 presents the pro forma effects of the recapitalization transactions described below under "—Pro Forma Combined Consolidated Statement of Operations" as if such recapitalization transactions, including the initial public offering of common units representing limited partner interests (the "Offering"), had occurred on January 1, 2013. The unaudited pro forma combined consolidated balance sheet as of June 30, 2014 presents the pro forma effects of the recapitalization transactions described below under "—Pro Forma Combined Consolidated Balance Sheet," as if such recapitalization transactions had occurred on June 30, 2014. The unaudited pro forma combined consolidated statement of operations for the year ended December 31, 2013 presents the pro forma effects of (i) the acquisition of Wildcat Permian Services ("Permian"), which was completed during the year ended December 31, 2013, as if it had occurred on January 1, 2013 and (ii) the recapitalization transactions, including the Offering, as if they occurred on January 1, 2013.
Our unaudited pro forma combined consolidated financial statements have been prepared to reflect adjustments to our historical financial statements that are (1) directly attributable to the pro forma transactions; (2) factually supportable; and (3) with respect to the unaudited pro forma combined consolidated statement of operations, expected to have a continuing impact on our results. The unaudited pro forma combined consolidated statement of operations do not include non-recurring items, including but not limited to Offering-related legal and advisory fees. The unaudited pro forma combined consolidated financial statements assume the underwriters will not exercise their option to purchase additional common units and reflects the impact of the acquisitions and recapitalization transactions, which comprise the following:
Pro Forma Combined Consolidated Balance Sheet
Our unaudited pro forma combined consolidated balance sheet has been derived from our unaudited historical condensed consolidated balance sheet as of June 30, 2014. The "Pro Forma Adjustments" column in our unaudited pro forma combined consolidated balance sheet contains the adjustments that we believe are appropriate to give effect to the recapitalization transactions, including the Offering, as if they had occurred as of June 30, 2014. Please read "—Note 2. Pro Forma Adjustments and Assumptions." The recapitalization transactions include:
- •
- each Class A common unit, Class B common unit and Class C common unit (collectively, the "Existing
Common Units") will split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units;
- •
- an aggregate of 18,213,502 Existing Common Units held by our existing partners will automatically convert into 18,213,502 subordinated units representing an 80.3% interest in us prior to this offering, and a 50.0% interest in us after the closing of this offering, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the "Remaining Existing Common Units");
F-3
- •
- the Remaining Existing Common Units will automatically convert on a one-for-one basis into 4,463,502 common units
representing a 12.3% interest in us;
- •
- the 45 general partner units in us held by our general partner will be recharacterized as a non-economic general partner
interest in us;
- •
- issuance of 13,750,000 common units to the public in this Offering representing a 37.7% interest in us;
- •
- the use of net proceeds from this Offering and from the borrowings under our revolving credit facility for the purposes
set forth in "Use of Proceeds;" and
- •
- other adjustments described in the notes to this section.
Pro Forma Combined Consolidated Statement of Operations
The unaudited pro forma combined consolidated statement of operations for the six months ended June 30, 2014 has been derived from our unaudited historical condensed consolidated statement of operations for the six months ended June 30, 2014 included elsewhere in this prospectus. The unaudited pro forma combined consolidated statement of operations for the year ended December 31, 2013 has been derived from (i) our audited historical consolidated statement of operations for the year ended December 31, 2013 and (ii) the audited historical financial statements of Permian included elsewhere in this prospectus.
The "Pro Forma Adjustments" column in our unaudited pro forma combined consolidated statement of operations contains the adjustments that we believe are appropriate to present the acquisition of Permian and recapitalization transactions, including the offering, on a pro forma basis as if they occurred on January 1, 2013. Please read "—Note 2. Pro Forma Adjustments and Assumptions." These adjustments include, among other things, the following:
- •
- adjustments in interest expense due to (i) additional interest associated with the debt incurred to finance such
acquisition and (ii) interest expense resulting from the repayment of such debt as a part of the Offering:
- •
- adjustments in depreciation and amortization expense due to a new fair value basis of assets as if these assets had been
acquired on April 1, 2013, the date in which the assets were put into service; and
- •
- other adjustments described in the notes to this section.
The incremental impact of the stand-alone public company costs and non-recurring transition costs, all of which are described below, are not reflected in the unaudited pro forma combined consolidated financial statements.
The unaudited pro forma combined consolidated financial statements do not reflect the pro forma effect of any of our other acquisitions completed in 2013 discussed in this prospectus, as they were deemed not significant.
The unaudited pro forma combined consolidated financial statements have been prepared in accordance with the acquisition method of accounting under existing United States generally accepted accounting principles, or GAAP standards, and the regulations of the United States Securities and Exchange Commission ("SEC"), and are not necessarily indicative of the financial position or results of operations that would have occurred if the Acquisitions and the recapitalization transactions had been completed on the dates indicated, nor is it indicative of the consolidated future operating results or financial position of JP Energy Partners LP. Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in connection with the unaudited pro forma combined consolidated financial statements.
F-4
Stand-Alone Public Company Costs
Upon completion of this Offering, we anticipate incurring incremental general and administrative expenses of approximately $3.5 million per year as a result of becoming a publicly traded partnership, including expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation. The unaudited pro forma combined consolidated financial statements do not reflect these incremental general and administrative expenses.
Non-Recurring Transaction Costs
The unaudited pro forma combined consolidated statements of operations also exclude certain non-recurring items that we expect to incur in connection with the pro forma transactions, including costs related to legal, accounting, and consulting services. We have incurred costs totaling approximately $0.2 million for transaction-related services during the year ended December 31, 2013 and minimal costs for the six months ended June 30, 2014 relating to the Permian acquisition.
"Unaudited Pro Forma Combined Consolidated Financial Statements" and the related notes should be read in conjunction with "Use of Proceeds," "Capitalization," "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Certain Relationships and Related Party Transactions," and our audited financial statements and the related notes included elsewhere in this prospectus.
F-5
JP Energy Partners LP
Unaudited Pro Forma Combined Consolidated Statement of Operations
Year Ended December 31, 2013
(in thousands, except unit and per unit data)
| |
|
For the period ended October 6, 2013 |
|
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
JP Energy Partners LP Historical |
Pro Forma Adjustments |
Pro Forma As Adjusted |
||||||||||
| |
Permian | ||||||||||||
Total revenues |
$ | 2,102,233 | $ | 2,968 | $ | — | $ | 2,105,201 | |||||
Costs and expenses: |
|||||||||||||
Cost of sales, excluding depreciation and amortization |
1,964,631 | — | — | 1,964,631 | |||||||||
Operating expense |
61,925 | 1,071 | — | 62,996 | |||||||||
General and administrative |
45,284 | 573 | (158) | (a) | 45,699 | ||||||||
Depreciation and amortization |
33,345 | 1,033 | 2,146 | (b) | 36,524 | ||||||||
Loss on disposal of assets |
1,492 | — | — | 1,492 | |||||||||
Operating income (loss) |
(4,444 | ) | 291 | (1,988 | ) | (6,141 | ) | ||||||
Other income (expense): |
|||||||||||||
Interest expense |
(9,075 | ) | — | 4,361 | (c) | (4,714 | ) | ||||||
Other income, net |
688 | — | — | 688 | |||||||||
Income (loss) from continuing operations before income tax |
(12,831 | ) | 291 | 2,373 | (10,167 | ) | |||||||
Income tax expense |
(208 | ) | (19 | ) | — | (227 | ) | ||||||
Net income (loss) from continuing operations |
$ | (13,039 | ) | $ | 272 | $ | 2,373 | $ | (10,394 | ) | |||
Common unitholders' interest in pro forma net income (loss) from continuing operations |
$ | (5,197 | ) | ||||||||||
Subordinated unitholders' interest in pro forma net income (loss) from continuing operations |
$ | (5,197 | ) | ||||||||||
Pro forma net income (loss) per common unit from continuing operations—basic and diluted |
$ | (0.29 | ) | ||||||||||
Pro forma net income (loss) per subordinated unit from continuing operations—basic and diluted |
$ | (0.29 | ) | ||||||||||
Weighted average number of limited partner units outstanding—basic and diluted |
|||||||||||||
Common units |
18,213,502 | ||||||||||||
Subordinated units |
18,213,502 | ||||||||||||
See accompanying notes to the unaudited pro forma combined consolidated statement of operations
F-6
JP Energy Partners LP
Unaudited Pro Forma Combined Consolidated Statement of Operations
Six Months Ended June 30, 2014
(in thousands, except unit and per unit data)
| |
JP Energy Partners LP Historical |
Pro Forma Adjustments |
Pro Forma As Adjusted |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
Total revenues |
$ | 865,817 | $ | — | $ | 865,817 | ||||
Costs and expenses: |
||||||||||
Cost of sales, excluding depreciation and amortization |
798,193 | — | 798,193 | |||||||
Operating expense |
35,266 | — | 35,266 | |||||||
General and administrative |
23,879 | (41) | (a) | 23,838 | ||||||
Depreciation and amortization |
20,165 | — | 20,165 | |||||||
Loss on disposal of assets |
661 | — | 661 | |||||||
Operating loss |
(12,347 | ) | 41 | (12,306 | ) | |||||
Other income (expense): |
||||||||||
Interest expense |
(5,551 | ) | 3,243 | (c) | (2,308 | ) | ||||
Loss on extinguishment of debt |
(1,634 | ) | 1,634 | (d) | — | |||||
Other income, net |
504 | — | 504 | |||||||
Loss from continuing operations before income tax |
(19,028 | ) | 4,918 | (14,110 | ) | |||||
Income tax expense |
(156 | ) | — | (156 | ) | |||||
Net loss from continuing operations |
$ | (19,184 | ) | $ | 4,918 | $ | (14,266 | ) | ||
Common unitholders' interest in pro forma net income (loss) from continuing operations |
$ | (7,133 | ) | |||||||
Subordinated unitholders' interest in pro forma net income (loss) from continuing operations |
$ | (7,133 | ) | |||||||
Pro forma net income (loss) per common unit from continuing operations—basic and diluted |
$ | (0.39 | ) | |||||||
Pro forma net income (loss) per subordinated unit from continuing operations—basic and diluted |
$ | (0.39 | ) | |||||||
Weighted average number of limited partner units outstanding—basic and diluted |
||||||||||
Common units |
18,213,502 | |||||||||
Subordinated units |
18,213,502 | |||||||||
See accompanying notes to the unaudited pro forma combined consolidated statement of operations
F-7
Unaudited Pro Forma Combined Consolidated Balance Sheet
As of June 30, 2014
(in thousands)
| |
JP Energy Partners LP Historical |
Pro Forma Adjustments |
Pro Forma As Adjusted |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
ASSETS |
||||||||||
Current assets |
||||||||||
Cash and cash equivalents |
$ | 1,126 | $ | 275,000 | (e) | $ | 108,451 | |||
|
(181,600) | (f) | ||||||||
|
75,000 | (f) | ||||||||
|
(19,875) | (h) | ||||||||
|
(41,200) | (i) | ||||||||
Restricted cash |
600 | 600 | ||||||||
Accounts receivable, net |
158,265 | (107,325) | (g) | 50,940 | ||||||
Receivables from related parties |
6,699 | 6,699 | ||||||||
Inventory |
19,551 | 19,551 | ||||||||
Prepaid expenses and other current assets |
8,195 | 8,195 | ||||||||
Total current assets |
194,436 | — | 194,436 | |||||||
Non-current assets |
||||||||||
Property, plant and equipment, net |
232,690 | 232,690 | ||||||||
Goodwill |
248,721 | 248,721 | ||||||||
Intangible assets, net |
157,468 | 157,468 | ||||||||
Deferred financing costs and other assets, net |
9,157 | (2,759) | (h) | 6,398 | ||||||
Total non-current assets |
648,036 | (2,759 | ) | 645,277 | ||||||
Total Assets |
$ | 842,472 | $ | (2,759 | ) | $ | 839,713 | |||
LIABILITIES AND PARTNERS' CAPITAL |
||||||||||
Current liabilities |
||||||||||
Accounts payable |
$ | 123,262 | $ | 123,262 | ||||||
Accrued liabilities |
24,938 | (254) | (f) | 24,684 | ||||||
Capital leases and short-term debt |
992 | 992 | ||||||||
Customer deposits and advances |
1,854 | 1,854 | ||||||||
Current portion of long-term debt |
364 | 364 | ||||||||
Total current liabilities |
151,410 | (254 | ) | 151,156 | ||||||
Non-current liabilities |
||||||||||
Long-term debt |
182,958 | (181,600) | (f) | 76,358 | ||||||
|
75,000 | (f) | ||||||||
Other long-term liabilities |
2,598 |
2,598 |
||||||||
Total Liabilities |
336,966 | (106,854 | ) | 230,112 | ||||||
Partners' capital |
||||||||||
Series D preferred units |
40,057 | (40,057) | (i) | — | ||||||
General partner interest |
(12,323 | ) | 12,323 | (i) | — | |||||
Class A common units (20,929,938 authorized, issued and outstanding at June 30, 2014) |
394,393 | (394,393) | (g)(i) | — | ||||||
Class B common units (1,244,508 units authorized, and 1,226,844 units issued and outstanding at June 30, 2014) |
10,491 |
(10,491) |
(g)(i) |
— |
||||||
Class C common units (3,254,781 shares authorized, issued and outstanding at June 30, 2014) |
72,888 | (72,888) | (g)(i) | — | ||||||
Common units—public (13,750,000 issued and outstanding) |
— | 275,000 | (e) | 252,366 | ||||||
|
(22,634) | (h) | ||||||||
Common units—Other (4,463,502 issued and outstanding) |
— | 70,314 | (i) | 70,314 | ||||||
Subordinated units (18,213,502 issued and outstanding) |
— | 286,921 | (i) | 286,921 | ||||||
Total partners' capital |
505,506 | 104,095 | 609,601 | |||||||
Total Liabilities and Partners' Capital |
$ | 842,472 | $ | (2,759 | ) | $ | 839,713 | |||
See accompanying notes to the unaudited pro forma combined consolidated balance sheet
F-8
JP ENERGY PARTNERS LP
NOTES TO UNAUDITED PRO FORMA COMBINED CONSOLIDATED FINANCIAL STATEMENTS
1) Description of the Acquisition
On October 7, 2013, JP Development acquired all of the issued and outstanding equity interests of Permian for a total consideration of $212.8 million in cash. Permian owns and operates a long-term contracted oil pipeline system in Crockett and Reagan Counties, Texas. On February 12, 2014, we acquired Permian from JP Development as part of the Dropdown Assets as described in note 1 to our consolidated financial statements included elsewhere in this prospectus. Because JPE and JP Development are under common control, JPE is required under GAAP to account for the Permian acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, JPE reflected in its balance sheet the assets of Permian at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities. JPE also retrospectively recast its financial statements to include the operating results of Permian from the date these assets were originally acquired by JP Development (the dates upon which common control began). Goodwill associated with the acquisition totaled $108.4 million.
To fund the above acquisition, we increased borrowings during the year ended December 31, 2013 under our revolving credit facility by $43.0 million. As of December 31, 2013, our revolving credit facility carried a blended interest rate of 6.00% as well as an annual commitment fee of 0.5% on the unused capacity of the revolving credit facility. No pro forma adjustment was made for the additional interest due to the recapitalization transactions.
2) Pro Forma Adjustments and Assumptions
The adjustments are based on currently available information, certain estimates and assumptions. Therefore the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:
- (a)
- The
pro forma adjustment reflects the removal of non-recurring transaction expenses already incurred of $0.2 million and $41,000 related to the
Permian acquisition for the year ended December 31, 2013 and six months ended June 30, 2014, respectively.
- (b)
- The pro forma adjustment reflects depreciation expense for the adjusted fixed assets and amortization for definite-lived intangibles assuming the assets were placed into service on April 1, 2013, the date at which the assets started generating revenue.
The pro forma adjustment reflects the changes in depreciation expense from April 1, 2013 (the date the assets were placed into service) to October 6, 2013 (the date of acquisition), from recording the acquired fixed assets at fair value and depreciating those assets based on their respective estimated remaining useful lives. Asset values and the remaining useful lives were determined based upon third-party appraisals. We estimated the remaining useful lives of the fixed assets, ranging from four to twenty years, and depreciated those assets on a straight-line basis over their estimated remaining useful lives. The reduction to depreciation related to this adjustment was approximately $0.4 million for the pro forma combined consolidated statement of operations for the year ended December 31, 2013.
The pro forma adjustment reflects additional amortization expense from April 1, 2013 (the date the assets were placed into service) to October 6, 2013 (the date of acquisition), from recording the acquired intangible assets at fair value. The intangible assets include customer-related intangibles and asset values were based upon third-party appraisals. We estimated the remaining useful lives, ranging from nine to twenty-five years, of all acquired intangible assets and amortized those assets on a straight-line basis over their estimated remaining useful lives. The amount of amortization related to this adjustment was approximately $2.5 million for the
F-9
JP ENERGY PARTNERS LP
NOTES TO UNAUDITED PRO FORMA COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2) Pro Forma Adjustments and Assumptions (Continued)
- (c)
- The following table reflects the adjustments in our unaudited pro forma combined consolidated statement of operations to reflect the impact of adjustments to interest expense:
unaudited pro forma combined consolidated statement of operations for the year ended December 31, 2013.
| |
Year Ended December 31, 2013 |
Six Months Ended June 30, 2014 |
|||||
|---|---|---|---|---|---|---|---|
| |
(in thousands) |
||||||
Revolving credit facility(1) |
$ | 2,500 | $ | 1,250 | |||
Amortization of deferred financing costs(1) |
795 | 397 | |||||
Total new indebtness |
3,295 | 1,647 | |||||
Existing indebtness(2) |
(7,656 | ) | (4,890 | ) | |||
Pro forma net finance expenses |
$ | (4,361 | ) | $ | (3,243 | ) | |
- (1)
- Expected
interest expense on our anticipated borrowings under the revolving credit facility assuming an estimated weighted average annual interest rate of
2.00% and an unused commitment fee of 0.50%. A 0.125% increase or decrease in the weighted average annual interest rate on the revolving credit facility would increase or decrease pro forma interest
expense by $0.1 million annually.
- (2)
- Reflects an adjustment for the repayment of our revolving credit facility borrowings from the net offering proceeds. The resulting pro forma interest expense decreased $7.7 million and $4.9 million for the year ended December 31, 2013 and six months ended June 30, 2014, respectively.
- (d)
- Reflects
an adjustment to exclude historical loss on extinguishment of debt from the termination of the Wells Fargo Credit Agreement.
- (e)
- The
pro forma adjustment reflects the assumed gross proceeds of $275.0 million from the issuance and sale of 13,750,000 common units at an assumed
initial public offering price of $20.00 per unit. If the underwriters were to exercise their option to purchase 2,062,500 additional common units in full, gross proceeds to JP Energy
Partners LP would equal $316.3 million. To the extent the underwriters exercise their option to purchase additional common units, the proceeds received from the common units will be used
to redeem additional units from Lonestar.
- (f)
- The unaudited pro forma combined consolidated balance sheet reflects the repayment and incurrence of the following debt as if it had occurred on June 30, 2014:
| |
As of June 30, 2014 |
Pro Forma Adjustments |
Pro Forma, As Adjusted |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
(in thousands) |
|||||||||
Revolving credit facility(1)(2) |
$ | 181,600 | $ | (106,600 | ) | $ | 75,000 | |||
HBH notes payable |
1,376 | — | 1,376 | |||||||
Noncompete notes payable |
346 | — | 346 | |||||||
Total long-term debt |
$ | 183,322 | $ | (106,600 | ) | $ | 76,722 | |||
Less: Current maturities |
(364 | ) | — | (364 | ) | |||||
Total long-term debt, net of current maturities |
$ | 182,958 | $ | (106,600 | ) | $ | 76,358 | |||
- (1)
- Reflects
an adjustment in long-term debt due to the repayment of $181.6 million of borrowings under our revolving credit facility from the net
offering proceeds.
- (2)
- Currently, we anticipate borrowing approximately $75.0 million on our revolving credit facility upon the completion of this offering.
The adjustment also reflects the reduction in accrued interest payable of $0.3 million due to the repayment of borrowings under our revolving credit facility.
F-10
JP ENERGY PARTNERS LP
NOTES TO UNAUDITED PRO FORMA COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2) Pro Forma Adjustments and Assumptions (Continued)
- (g)
- The
pro forma adjustment reflects the $107.3 million distribution of accounts receivable that comprise our gross working capital assets to existing
unitholders as of June 30, 2014. Shortly before the closing of the offering, we will distribute accounts receivable to our existing unitholders in an amount that is based on the proceeds from
the offering, as well as offering expenses and the expected outstanding borrowings on our credit facility as of the date of the offering. The amount of accounts receivable to be distributed is
currently estimated to be $92.1 million based on assumed total gross proceeds from the offering of $275.0 million. The amount of accounts receivable that is actually distributed to our
unitholders will be increased or decreased from the $92.1 million estimate if the gross proceeds from the offering are more or less than $275.0 million. The $15.2 million
difference between the $107.3 million pro forma adjustment at June 30, 2014 and the estimated accounts receivable to be distributed shortly before the closing of the offering of
$92.1 million is due to (i) the expected balance under our revolving credit facility of $195.6 million at the closing of the offering compared to $181.6 million as of
June 30, 2014 and (ii) an additional $1.2 million to be paid to Lonestar in connection with the redemption of our outstanding Series D Preferred Units, represented by
$1.2 million of cumulative distributions that accrued on the Series D Preferred Units since June 30, 2014.
- (h)
- The
pro forma adjustment reflects the payment of estimated underwriting discounts and commissions, structuring fees and offering expenses.
- (i)
- The pro forma adjustment reflects the effect of the recapitalization transactions.
3) Pro Forma Net Loss per Unit
Pro forma net loss per unit is determined by dividing the pro forma net loss that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated unitholders under the two-class method by the number of common and subordinated units expected to be outstanding at the closing of the initial public offering. For purposes of this calculation, we assumed that the minimum quarterly distribution was made to all unitholders for each quarter during the periods presented.
Pro forma JP Energy Partners LP earnings (loss) per unit is calculated using 18,213,502 common units and 18,213,502 subordinated units. The common and subordinated unitholders represent an aggregate 100% limited partner interest in JP Energy Partners LP. All units were assumed to have been outstanding since January 1, 2013.
Basic and diluted pro forma net loss per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of JP Energy Partners LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net loss per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.
F-11
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(Unaudited)
| |
December 31, 2013 |
June 30, 2014 |
Pro Forma June 30, 2014 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
ASSETS |
||||||||||
Current assets |
||||||||||
Cash and cash equivalents |
$ | 3,234 | $ | 1,126 | 1,126 | |||||
Restricted cash |
— | 600 | 600 | |||||||
Accounts receivable less allowance for doubtful accounts of $1,207 and $1,335, respectively |
122,919 | 158,265 | 158,265 | |||||||
Receivables from related parties |
2,742 | 6,699 | 6,699 | |||||||
Inventory |
38,579 | 19,551 | 19,551 | |||||||
Prepaid expenses and other current assets |
4,991 | 8,195 | 8,195 | |||||||
| | | | | | | | | | | |
Total current assets |
172,465 | 194,436 | 194,436 | |||||||
| | | | | | | | | | | |
Non-current assets |
||||||||||
Property, plant and equipment, net |
238,093 | 232,690 | 232,690 | |||||||
Goodwill |
250,705 | 248,721 | 248,721 | |||||||
Intangible assets, net |
175,101 | 157,468 | 157,468 | |||||||
Deferred financing costs and other assets, net |
7,038 | 9,157 | 9,157 | |||||||
| | | | | | | | | | | |
Total non-current assets |
670,937 | 648,036 | 648,036 | |||||||
| | | | | | | | | | | |
Total Assets |
$ | 843,402 | $ | 842,472 | 842,472 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
LIABILITIES AND PARTNERS' CAPITAL |
||||||||||
Current liabilities |
||||||||||
Accounts payable |
$ | 95,765 | $ | 123,262 | 123,262 | |||||
Payables to related parties |
1,274 | — | 107,325 | |||||||
Accrued liabilities |
22,748 | 24,938 | 24,938 | |||||||
Capital leases and short-term debt |
538 | 992 | 992 | |||||||
Customer deposits and advances |
2,722 | 1,854 | 1,854 | |||||||
Current portion of long-term debt |
698 | 364 | 364 | |||||||
| | | | | | | | | | | |
Total current liabilities |
123,745 | 151,410 | 258,735 | |||||||
Non-current liabilities |
||||||||||
Long-term debt |
183,148 | 182,958 | 182,958 | |||||||
Note payable to related party |
1,000 | — | — | |||||||
Other long-term liabilities |
2,116 | 2,598 | 2,598 | |||||||
| | | | | | | | | | | |
Total Liabilities |
310,009 | 336,966 | 444,291 | |||||||
| | | | | | | | | | | |
Commitments and contingencies |
||||||||||
Partners' capital |
||||||||||
Predecessor capital |
304,065 | — | — | |||||||
Series D preferred units |
— | 40,057 | 40,057 | |||||||
General partner interest |
404 | (12,323 | ) | (12,323 | ) | |||||
Class A common units (8,004,368 units and 20,929,938 authorized, issued and outstanding at December 31, 2013 and June 30, 2014, respectively) |
140,752 | 394,393 | 305,996 | |||||||
Class B common units (1,244,508 units authorized and 1,206,844 and 1,226,844 issued and outstanding at December 31, 2013 and June 30, 2014, respectively) |
11,366 | 10,491 | 5,309 | |||||||
Class C common units (3,254,781 shares authorized, issued and outstanding as of December 31, 2013 and June 30, 2014, respectively) |
76,806 | 72,888 | 59,142 | |||||||
| | | | | | | | | | | |
Total partners' capital |
533,393 | 505,506 | 398,181 | |||||||
| | | | | | | | | | | |
Total Liabilities and Partners' Capital |
$ | 843,402 | $ | 842,472 | 842,472 | |||||
| | | | | | | | | | | |
| | | | | | | | | | | |
See accompanying notes to condensed consolidated financial statements.
F-12
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except unit and per unit data)
(Unaudited)
| |
Six Months Ended June 30, | ||||||
|---|---|---|---|---|---|---|---|
| |
2013 | 2014 | |||||
REVENUES: |
|||||||
Crude oil sales |
$ | 877,318 | $ | 725,815 | |||
Gathering, transportation and storage fees |
8,046 | 20,386 | |||||
NGL and refined product sales (including sales to related parties of $8,251 and $6,933 in the six months ended June 30, 2013 and 2014, respectively) |
90,500 | 107,098 | |||||
Refined products terminals and storage fees (including sales to related parties of $1,610 and $1,447 in the six months ended June 30, 2013 and 2014, respectively) |
5,964 | 5,668 | |||||
Other revenues |
5,976 | 6,850 | |||||
| | | | | | | | |
Total revenues |
987,804 | 865,817 | |||||
| | | | | | | | |
COSTS AND EXPENSES: |
|||||||
Cost of sales, excluding depreciation and amortization |
918,957 | 798,193 | |||||
Operating expense |
28,202 | 35,266 | |||||
General and administrative |
20,313 | 23,879 | |||||
Depreciation and amortization |
15,186 | 20,165 | |||||
Loss on disposal of assets, net |
998 | 661 | |||||
| | | | | | | | |
Total costs and expenses |
983,656 | 878,164 | |||||
| | | | | | | | |
OPERATING INCOME (LOSS) |
4,148 | (12,347 | ) | ||||
OTHER INCOME (EXPENSE) |
|||||||
Interest expense |
(3,815 | ) | (5,551 | ) | |||
Loss on extinguishment of debt |
— | (1,634 | ) | ||||
Other income, net |
195 | 504 | |||||
| | | | | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
528 | (19,028 | ) | ||||
Income tax expense |
(305 |
) |
(156 |
) |
|||
| | | | | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS |
223 | (19,184 | ) | ||||
DISCONTINUED OPERATIONS |
|||||||
Net loss from discontinued operations, including loss on disposal of $7,288 in 2014 |
(23 |
) |
(9,608 |
) |
|||
| | | | | | | | |
NET INCOME (LOSS) |
$ | 200 | $ | (28,792 | ) | ||
| | | | | | | | |
| | | | | | | | |
Net (income) loss attributable to preferred unitholders |
$ | 445 | $ | (57 | ) | ||
Net (income) loss attributable to predecessor capital |
(5,063 | ) | 2,046 | ||||
| | | | | | | | |
Net income (loss) attributable to common unitholders |
$ | (4,418 | ) | $ | (26,803 | ) | |
| | | | | | | | |
Basic and diluted loss per unit: |
|||||||
Weighted average number of common units outstanding |
11,205,946 | 22,265,269 | |||||
Basic and diluted loss per common unit from continuing operations |
$ | (0.39 | ) | $ | (0.77 | ) | |
Basic and diluted loss per common unit from discontinued operations |
$ | (0.00 | ) | $ | (0.43 | ) | |
Basic and diluted loss per common unit |
$ | (0.39 | ) | $ | (1.20 | ) | |
Distribution per common unit |
$ | 1.00 | $ | — | |||
Pro forma income (loss) per unit—basic and diluted |
$ | (0.62 | ) | ||||
See accompanying notes to condensed consolidated financial statements.
F-13
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(in thousands, except unit data)
(Unaudited)
| |
Units | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Series D Preferred |
General Partner |
Class A Common |
Class B Common |
Class C Common |
Total | |||||||||||||
Balance—January 1, 2014 |
— | 45 | 8,004,368 | 1,206,844 | 3,254,781 | 12,466,038 | |||||||||||||
Issuance of Class A Common Units |
— | — | 363,636 | — | — | 363,636 | |||||||||||||
Issuance of Class B Common Units |
— | — | — | 20,000 | — | 20,000 | |||||||||||||
Common control acquisition |
— | — | 12,561,934 | — | — | 12,561,934 | |||||||||||||
Issuance of Preferred Units |
1,818,182 | — | — | — | — | 1,818,182 | |||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Balance—June 30, 2014 |
1,818,182 | 45 | 20,929,938 | 1,226,844 | 3,254,781 | 27,229,790 | |||||||||||||
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| |
Series D Preferred |
General Partner |
Predecessor Capital |
Class A Common |
Class B Common |
Class C Common |
Total | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance—January 1, 2014 |
$ | — | $ | 404 | $ | 304,065 | $ | 140,752 | $ | 11,366 | $ | 76,806 | $ | 533,393 | ||||||||
Contribution from the Predecessor |
— | — | 4,321 | — | — | — | 4,321 | |||||||||||||||
Issuance of Class A Common Units |
— | — | — | 8,000 | — | — | 8,000 | |||||||||||||||
Issuance of Preferred Units |
40,000 | — | — | — | — | — | 40,000 | |||||||||||||||
Unit-based compensation |
— | — | — | — | 584 | — | 584 | |||||||||||||||
Common control acquisition |
— | (12,727 | ) | (306,340 | ) | 267,067 | — | — | (52,000 | ) | ||||||||||||
Net loss |
57 | — | (2,046 | ) | (21,426 | ) | (1,459 | ) | (3,918 | ) | (28,792 | ) | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance—June 30, 2014 |
$ | 40,057 | $ | (12,323 | ) | $ | — | $ | 394,393 | $ | 10,491 | $ | 72,888 | $ | 505,506 | |||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
See accompanying notes to condensed consolidated financial statements.
F-14
JP ENERGY PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
| |
Six Months Ended June 30, |
||||||
|---|---|---|---|---|---|---|---|
| |
2013 | 2014 | |||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|||||||
Net income (loss) |
$ | 200 | $ | (28,792 | ) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities including discontinued operations: |
|||||||
Depreciation and amortization |
16,603 | 21,599 | |||||
Goodwill impairment |
— | 1,984 | |||||
Derivative valuation changes |
(90 | ) | 617 | ||||
Amortization of deferred financing costs |
562 | 459 | |||||
Loss on extinguishment of debt |
— | 1,634 | |||||
Unit-based compensation expenses |
371 | 584 | |||||
Loss on disposal of assets |
998 | 7,709 | |||||
Bad debt expense |
331 | 555 | |||||
Other non-cash items |
56 | (74 | ) | ||||
Changes in working capital, net of acquired assets and liabilities: |
|||||||
Accounts receivable |
1,182 | (35,968 | ) | ||||
Receivable from related parties |
1,085 | (3,957 | ) | ||||
Inventory |
(4,996 | ) | 18,998 | ||||
Prepaid expenses and other current assets |
2,813 | (3,745 | ) | ||||
Accounts payable and other accrued liabilities |
5,700 | 28,576 | |||||
Payables to related parties |
902 | (1,464 | ) | ||||
Customer deposits and advances |
(960 | ) | (868 | ) | |||
Changes in other assets and liabilities |
21 | (275 | ) | ||||
| | | | | | | | |
NET CASH PROVIDED BY OPERATING ACTIVITIES |
24,778 | 7,572 | |||||
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES |
|||||||
Capital expenditures |
(13,075 | ) | (14,808 | ) | |||
Acquisitions of businesses, net of cash acquired |
(1,003 | ) | — | ||||
Restricted cash deposit |
— | (600 | ) | ||||
Proceeds received from sale of assets |
92 | 10,472 | |||||
| | | | | | | | |
NET CASH USED IN INVESTING ACTIVITIES |
(13,986 | ) | (4,936 | ) | |||
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES |
|||||||
Proceeds from revolving line of credit |
8,000 | 274,800 | |||||
Payments on revolving line of credit |
(8,000 | ) | (270,757 | ) | |||
Payments on long-term debt |
(1,895 | ) | (4,619 | ) | |||
Payment of related party note payable |
— | (1,000 | ) | ||||
Payments on capital leases |
(98 | ) | (54 | ) | |||
Payments on financed insurance premium |
(2,485 | ) | (35 | ) | |||
Change in cash overdraft |
— | 498 | |||||
Debt issuance costs |
(215 | ) | (2,830 | ) | |||
Distributions to unitholders |
(5,127 | ) | — | ||||
Issuance of Series D preferred units |
— | 40,000 | |||||
Issuance of common units |
— | 8,000 | |||||
Common control acquisition |
— | (52,000 | ) | ||||
Net distribution to /contributions from the Predecessor |
(654 | ) | 4,321 | ||||
Tax withholding on unit-based vesting |
— | (164 | ) | ||||
Other |
(1,008 | ) | (904 | ) | |||
| | | | | | | | |
NET CASH USED IN FINANCING ACTIVITIES |
(11,482 | ) | (4,744 | ) | |||
| | | | | | | | |
Net change in cash and cash equivalents |
(690 | ) | (2,108 | ) | |||
Cash and cash equivalents balance, beginning of period |
10,099 | 3,234 | |||||
| | | | | | | | |
Cash and cash equivalents balance, end of period |
$ | 9,409 | $ | 1,126 | |||
| | | | | | | | |
| | | | | | | | |
SUPPLEMENTAL DISCLOSURES: |
|||||||
Non-cash investing and financing transactions: |
|||||||
Accrued capital expenditures |
1,144 | 2,773 | |||||
See accompanying notes to condensed consolidated financial statements.
F-15
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts, except per unit data, are in
thousands)
(Unaudited)
1. Business and Basis of Presentation
Business. The unaudited condensed consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries ("JPE" or the "Partnership"). The Partnership was formed in May 2010 by members of management and was further capitalized in June 2011 by ArcLight Capital Partners, LLC ("ArcLight") to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership's operations currently consist of: (i) crude oil pipelines and storage; (ii) crude oil supply and logistics; (iii) refined products terminals and storage; and (iv) natural gas liquid ("NGL") distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. JP Energy GP II LLC ("GP II") is the Partnership's general partner.
JP Development. On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership ("JP Development"), for the express purpose of supporting JPE's growth. Since its formation, JP Development has acquired a portfolio of midstream assets that have been developed for eventual sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development made the following acquisitions since its formation in July 2012:
- •
- On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company
("Parnon Gathering"), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition,
Parnon Gathering LLC was renamed to JP Energy Marketing LLC ("JPEM").
- •
- On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH
Propane, LLC, an Arkansas limited liability company ("BMH"), which is engaged in the retail and wholesale propane and refined fuel distribution business.
- •
- On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil
Field Services, Inc., a Texas Corporation ("AOFS"), which is engaged in the crude oil trucking business.
- •
- On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability
("Wildcat Permian") that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company ("JP Permian"). JP Permian is engaged in the transportation of crude oil by
pipeline.
- •
- On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development ("JP Liquids"), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation ("Highway Pipeline"), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.
Common Control Acquisition between JPE and JP Development. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, the Partnership acquired (i) certain marketing and trucking businesses of JPEM (the "Parnon Gathering Assets"), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the "Dropdown Assets")
F-16
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
1. Business and Basis of Presentation (Continued)
from JP Development for an aggregate purchase price of approximately $319.1 million (the "Common Control Acquisition"), which comprised of 12,561,934 JPE Class A Common Units and $52.0 million cash. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility.
Basis of Presentation. Because JPE and JP Development are under common control, JPE is required under generally accepted accounting principles in the United States ("GAAP") to account for this Common Control Acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, JPE reflected in its balance sheet the Dropdown Assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. JPE also retrospectively adjusted its financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).
The historical assets and liabilities and the operating results of the Dropdown Assets have been "carved out" from JP Development's consolidated financial statements using JP Development's historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. JPE's historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification. Management believes the assumptions underlying the consolidated financial statements are reasonable. However, the combined financial statements do not fully reflect what the Partnership, including the Dropdown Assets' balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under JPE management during the periods presented. As a result, historical financial information is not necessarily indicative of what the Partnership's balance sheet, results of operations, and cash flows will be in the future.
JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the six months ended June 30, 2013 and 2014. The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity. The net balances due to JPE from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.
The total purchase price from the Common Control Acquisition exceeded the book value of the assets acquired. As a result, the excess of the total purchase price over the book value of the assets
F-17
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
1. Business and Basis of Presentation (Continued)
acquired of $12.7 million was considered a deemed distribution by the general partner and is included in general partner interest in Partners' Capital.
The "predecessor capital" included in Partners' Capital represented JP Development's net investment in the Dropdown Assets, which included the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development. Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled, as a result, were considered deemed contributions or distributions and are included in JP Development's net investment.
Net income (loss) attributable to the Dropdown Assets prior to the Partnership's acquisition of such assets was not available for distribution to the Partnership's unitholders. Therefore, this income (loss) was not allocated to the limited partners for the purpose of calculating net income (loss) per common unit; instead, the income (loss) was allocated to predecessor capital.
The results of operations for the six months ended June 30, 2013 and 2014 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation of the financial position and results of operations for such interim periods in accordance with GAAP. Although the Partnership believes the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). These unaudited condensed consolidated interim financial statements and the notes thereto should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2013.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The unaudited condensed consolidated financial statements of the Partnership have been prepared in accordance with GAAP for interim financial information. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying unaudited condensed consolidated financial statements.
Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management's available knowledge of current and expected future events, actual results could be different from those estimates.
Fair value measurement. The Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Partnership determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant
F-18
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
2. Summary of Significant Accounting Policies (Continued)
assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.
The fair value of the Partnership's derivatives (see Note 8) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The Partnership does not have any other assets or liabilities measured at fair value on a recurring basis.
The Partnership's other financial instruments consist primarily of cash and cash equivalents and long term debt. The fair value of long-term debt approximates the carrying value as the underlying instruments are at rates similar to current rates offered to the Partnership for debt with the same remaining maturities.
Restricted Cash. Restricted cash consists of cash balances which are restricted as to withdrawal or usage and include cash to secure crude oil production taxes payable to the applicable taxing authorities.
Goodwill. The Partnership has recorded goodwill in connection with its historical acquisitions. Upon acquisition, these companies have been either combined into one of the Partnership existing operating units or managed on a stand-alone basis as an individual operating unit. Goodwill recorded in connection with these acquisitions is subject to an annual assessment for impairment, which the Partnership performs at the operating unit level for each operating unit that carries a balance of goodwill. Each of Partnership's operating units is organized into one of four business segments: Crude Oil Pipelines and Storage, Crude Oil Supply and Logistics, Refined Products Terminals and Storage, and NGL Distribution and Sales. Goodwill is required to be measured for impairment at the operating segment level or one level below the operating segment level for which discrete financial information is available, and the Partnership has determined following reporting units for the purpose of assessing goodwill impairments.
| Operating Segments | Reporting Units | |
|---|---|---|
| Crude Oil Pipelines and Storage | JP Permian | |
| JPE Storage | ||
| Crude Oil Supply and Logistics | JPE Product Supply and Logistics | |
| Refined Product Terminals and Storage | ATT and Caddo Mills | |
| NGL Distribution and Sales | Pinnacle Propane | |
| Pinnacle Propane Express | ||
| JP Liquids |
F-19
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
2. Summary of Significant Accounting Policies (Continued)
The Partnership's goodwill impairment assessment is performed at year-end, or more frequently if events or circumstances arise which indicate that goodwill may be impaired.
The Partnership has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step fair value-based impairment test described below. The Partnership can choose to perform the qualitative assessment on none, some or all of its reporting units. The Partnership can also bypass the qualitative assessment for any reporting unit in any period and proceed directly to step one of the impairment test, and then resume performing the qualitative assessment in any subsequent period. Qualitative indicators including deterioration in macroeconomic conditions, declining financial performance that, among other things, may trigger the need for annual or interim impairment testing of goodwill associated with one or all of the reporting units. If the Partnership believes that, as a result of its qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. The first step of the two-step fair value-based test involves comparing the fair value of each of the Partnership's reporting units with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the reporting unit's goodwill to the implied fair value of its goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss would be recorded as a reduction to goodwill with a corresponding charge to operating expense.
The Partnership determines the fair value of its reporting units using a weighted combination of the discounted cash flow and market multiple valuation approaches, with heavier weighting on the discounted cash flow method, as in management's opinion, this method currently results in the most accurate calculation of a reporting unit's fair value. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, discount rates, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in its impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.
Under the discounted cash flow method, the Partnership determines fair value based on the estimated future cash flows of each reporting unit (including estimates for capital expenditures), discounted to present value using risk-adjusted industry discount rates, which reflect the overall level of inherent risk of a reporting unit and the rate of return an outside investor would expect to earn. Cash flow projections are derived from budgeted amounts and operating forecasts (typically a one-year model) plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur, along with a terminal value derived from the reporting unit's earnings before interest, taxes, depreciation and amortization, as well as other non-cash items or one-time non-recurring items (Adjusted EBITDA) using the Gordon Growth Model.
Under the market multiple approach, the Partnership determines the estimated fair value of each of its reporting units by applying transaction multiples derived from observable market data to each
F-20
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
2. Summary of Significant Accounting Policies (Continued)
reporting unit's projected Adjusted EBITDA and then averaging that estimate with similar historical calculations using either a one, two or three year average. The Partnership adds a reasonable control premium, which is estimated as the premium that would be received in a sale of the reporting unit in an orderly transaction between market participants.
During the second quarter of 2014, due to the actual operating results for the six months period ended June 30, 2014 being significantly below management's budget for certain reporting units, a two-step fair-value based goodwill impairment analysis was performed for five of the seven of the Partnership's reporting units, namely JP Permian, JPE Product Supply and Logistics, Pinnacle Propane, Pinnacle Propane Express, and JP Liquids. Management engaged a third party valuation expert to assist performing the analysis using the valuation approaches described in the preceding paragraphs. The analysis indicated that the implied fair value of each of these reporting units was in excess of its carrying value. Based on the analysis, management concluded that no impairment was indicated at any reporting unit.
During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the JPE Product Supply and Logistics reporting unit, the Partnership allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by the Partnership. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.
Comprehensive Income. For the six months ended June 30, 2013 and 2014, comprehensive income (loss) was equal to net income (loss).
The unaudited pro forma condensed consolidated balance sheet as of June 30, 2014 has been prepared to give effect of the distribution to existing unitholders as if it had occurred or existed on June 30, 2014. The unaudited pro forma condensed consolidated balance sheet does not reflect any proceeds of this offering.
Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, the Partnership intends to distribute approximately $107,325,000 of accounts receivable that comprise our gross working capital assets to existing unitholders. Unaudited basic and diluted pro forma earnings per common unit for the six months ended June 30, 2014 has been included and discussed in Note 4.
3. Discontinued Operations
On June 30, 2014, the Partnership ("Seller") entered into and simultaneously closed an Asset Purchase Agreement (the "Purchase Agreement") with Gold Spur Trucking, LLC ("Buyer"), pursuant to which the Seller sold all the trucking and related assets and activities in North Dakota, Montana and Wyoming (the "Bakken Business") to the Buyer for a purchase price of $9,100,000. As a result, the Partnership recognized a loss on this sale of approximately $7,288,000 during the second quarter of 2014, which primarily relates to the write-off of a customer contract associated with the Bakken Business. In addition, immediately prior to the sale, the Partnership allocated $1,984,000 of goodwill to
F-21
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
3. Discontinued Operations (Continued)
the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that was retained by the Partnership. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.
The Bakken Business's operations have been classified as discontinued operations for all periods in the condensed consolidated statements of operations. Prior to the classification as discontinued operations, the Partnership had reported the Bakken Business in its crude oil supply and logistics segment. The following table summarizes selected financial information related to the Bakken Business's operations in the six months ended June 30, 2013 and 2014.
| |
Six months ended June 30, |
||||||
|---|---|---|---|---|---|---|---|
| |
2013 | 2014 | |||||
Revenue from discontinued operations |
$ | 10,375 | $ | 7,865 | |||
Net loss of discontinued operations, net of taxes, including loss on disposal of $7,288 in 2014 |
(23 | ) | (9,608 | ) | |||
4. Net Loss Per Unit
Income (loss) per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships ("MLPs") when incentive distribution rights ("IDRs") and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. For the six months ended June 30, 2013 and 2014, diluted income (loss) per unit was equal to basic income (loss) per unit because all instruments were antidilutive.
The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented.
| |
Six Months Ended June 30, |
||||||
|---|---|---|---|---|---|---|---|
| |
2014 | 2013 | |||||
Series A Preferred Units |
— | 524,746 | |||||
Series B Preferred Units |
— | 552,348 | |||||
Series C Preferred Units |
— | 59,270 | |||||
Series D Preferred Units |
1,818,182 | — | |||||
The Series A, Series B and Series C preferred units earned cumulative distributions each quarter equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common and (b) the minimum quarterly
F-22
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
4. Net Loss Per Unit (Continued)
distribution of $0.50 per unit. The net income attributable to preferred units includes cumulative distributions declared and the Series A, Series B and Series C preferred units' proportionate share of net income for the six months ended June 30, 2013. On August 1, 2013, all then-outstanding Series A, Series B and Series C preferred units were converted to common units on a one-for-one basis.
The Series D preferred units (see Note 9) earn cumulative distributions each quarter, commencing with the quarter ending June 30, 2014, equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common and (b) $0.66 per unit. For the six months ended June 30, 2014 the Partnership recorded a Paid in Kind ("PIK") distribution of $1,200,000. The net loss attributable to preferred units includes the Series D preferred units' proportionate share of net loss for the six months ended June 30, 2014.
Unaudited pro forma basic and diluted net loss per unit attributable to common unitholders for the six months ended June 30, 2014 has been computed to reflect the number of units that would have been required to be issued to generate sufficient proceeds to fund the distributions of $107,325,000 million to existing unitholders based on an assumed offering price of $20.00 per unit (but such number of additional units shall not exceed the number of units to be sold in this offering). The unaudited pro forma basic and diluted earnings per unit for the six months ended June 30, 2014 does not give effect to the initial public offering and the use of proceeds therefrom. The following table sets forth the computation of the Partnership's unaudited pro forma basic and diluted net loss per unit for the six months ended June 30, 2014:
| |
Six Months Ended June 30, 2014 (unaudited) Common Units |
|||
|---|---|---|---|---|
Numerator |
||||
Loss from continuing operations |
$ | (19,184 | ) | |
Net loss attributable to preferred unitholders |
(57 | ) | ||
Net income attributable to predecessor capital |
2,046 | |||
Net loss from continuing operations attributable to common unitholders |
(17,195 | ) | ||
Denominator |
||||
Weighted average units outstanding post contribution—basic and diluted |
22,265,269 | |||
Pro forma adjustment to reflect the assumed distribution |
5,366,250 | |||
| | | | | |
Weighted average units outstanding used in computing the pro forma net income per unit—basic and diluted |
27,631,519 | |||
| | | | | |
Pro forma net income per unit—basic and diluted |
$ | (0.62 | ) | |
| | | | | |
| | | | | |
F-23
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
5. Inventory
Inventory consists of the following as of December 31, 2013 and June 30, 2014:
| |
December 31, 2013 |
June 30, 2014 |
|||||
|---|---|---|---|---|---|---|---|
Crude oil |
$ | 31,099 | $ | 12,873 | |||
NGLs |
5,274 | 4,459 | |||||
Diesel |
438 | 380 | |||||
Materials, supplies and equipment |
1,768 | 1,839 | |||||
| | | | | | | | |
Total inventory |
$ | 38,579 | $ | 19,551 | |||
| | | | | | | | |
| | | | | | | | |
6. Goodwill and Intangible Assets
Intangible assets consist of the following at December 31, 2013 and June 30, 2014:
| |
Balance at December 31, 2013 |
Additions | Disposals | Amortization | Balance at June 30, 2014 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Customer relationships |
$ | 72,991 | $ | — | $ | — | $ | (3,696 | ) | 69,295 | ||||||
Noncompete agreements |
2,336 | — | — | (459 | ) | 1,877 | ||||||||||
Trade names |
1,863 | — | — | (150 | ) | 1,713 | ||||||||||
Customer contract |
97,674 | — | (8,060 | ) | (5,244 | ) | 84,370 | |||||||||
Favorable lease |
192 | — | — | (2 | ) | 190 | ||||||||||
Other |
45 | 3 | — | (25 | ) | 23 | ||||||||||
| | | | | | | | | | | | | | | | | |
Total |
$ | 175,101 | $ | 3 | $ | (8,060 | ) | $ | (9,576 | ) | $ | 157,468 | ||||
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Goodwill activity in the six months ended June 30, 2014 consists of the following:
| |
Crude oil pipelines and storage |
Crude oil supply and logistics |
Refined products terminals and storage |
NGL distribution and sales |
Total | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2013 |
108,162 | 50,045 | 61,163 | 31,335 | 250,705 | |||||||||||
Goodwill acquired during the year |
— | — | — | — | — | |||||||||||
Disposals |
— | (1,984 | ) | — | — | (1,984 | ) | |||||||||
| | | | | | | | | | | | | | | | | |
Balance at December 31, 2013 |
$ | 108,162 | $ | 48,061 | $ | 61,163 | $ | 31,335 | $ | 248,721 | ||||||
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
F-24
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
6. Goodwill and Intangible Assets (Continued)
The estimated future amortization expense for amortizable intangible assets to be recognized is as follows:
2014 |
$ | 8,729 | ||
2015 |
17,337 | |||
2016 |
16,944 | |||
2017 |
16,092 | |||
2018 |
15,149 | |||
Thereafter |
83,217 | |||
| | | | | |
Total |
$ | 157,468 | ||
| | | | | |
| | | | | |
7. Long-Term Debt
Long-term debt consists of the following at December 31, 2013 and June 30, 2014:
| |
December 31, 2013 | June 30, 2014 | |||||
|---|---|---|---|---|---|---|---|
Revolving loans |
177,557 | 181,600 | |||||
F&M bank loans |
4,135 | — | |||||
HBH notes payable |
1,470 | 1,376 | |||||
Related party note payable |
1,000 | — | |||||
Reynolds note payable |
344 | — | |||||
Noncompete notes payable |
340 | 346 | |||||
| | | | | | | | |
Total long-term debt |
$ | 184,846 | $ | 183,322 | |||
Less: Current maturities |
(698 | ) | (364 | ) | |||
| | | | | | | | |
Total long-term debt, net of current maturities |
$ | 184,148 | $ | 182,958 | |||
| | | | | | | | |
| | | | | | | | |
Wells Fargo Credit Agreement. The Partnership had a $20,000,000 working capital revolving credit facility and a $180,000,000 acquisition revolving credit facility with Wells Fargo Bank, N.A. (the "WFB Credit Agreement"). The Partnership's outstanding borrowings under the WFB Credit Agreement were collateralized by all of the Partnership's assets and a certain letters of credit, as required.
On February 12, 2014, the Partnership entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement. As a result of the termination of the WFB Credit Agreement, the Partnership wrote off $1,634,000 of deferred financing costs during the six months ended June 30, 2014.
Bank of America Credit Agreement. On February 12, 2014, the Partnership entered into a credit agreement with Bank of America, N.A. (the "BOA Credit Agreement) for working capital requirements, for the acquisition of entities, and to pay off its existing WFB Commitments and F&M Loans. The BOA Credit Agreement consists of a $275,000,000 revolving loan. The BOA Credit Agreement will mature on February 12, 2019. The Partnership's obligations under the BOA Credit Agreement are collateralized by substantially all of the Partnership's assets.
F-25
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
7. Long-Term Debt (Continued)
Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable margin. The initial applicable margin is (a) 2.00% for prime rate borrowings and 3.00% for LIBOR borrowings. The applicable margin is subject to an adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.
As of June 30, 2014, the unused balance of the BOA Credit Agreement was $47,120,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $46,280,000 at June 30, 2014. The Partnership is required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.
The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:
- •
- Maintenance of certain financial covenants including a consolidated total leverage ratio of not more than 4.50 to 1.00
(which will be increased to 4.75 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated senior secured leverage ratio of not more than 3:00 to 1:00
and a consolidated interest coverage ratio of not less than 2.50 to 1.00.
- •
- Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual
audited financial statement reporting.
- •
- Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.
The Partnership was not in compliance with the leverage ratio covenant for the quarter ended June 30, 2014, which noncompliance was waived pursuant to a waiver received by the Partnership on August 5, 2014.
F&M Bank Loans. The F&M Bank loans had a credit commitment of $9,000,000. The F&M Bank loans were paid off in full on February 12, 2014, with the proceeds from the BOA Credit Agreement.
Related Party Note Payable. On November 5, 2013, the Partnership issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. On March 20, 2014, the Partnership repaid the promissory note in full.
8. Derivative Instruments
The Partnership is exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, the Partnership has established comprehensive risk management policies and procedures. The Board of Directors is responsible for the
F-26
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
8. Derivative Instruments (Continued)
overall management of these risks, including monitoring exposure limits. The Partnership does not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. That is, the Partnership does not speculate using derivative instruments.
Commodity Price Risk. The Partnership's NGL distribution and sales segment is exposed to market risks related to the volatility of propane prices. Management believes it is prudent to limit the variability of a portion of the Partnership's propane purchases. To meet this objective, the Partnership uses a combination of financial instruments including, but not limited to, forward physical contracts and financial swaps to manage its exposure to market fluctuations in propane prices. During the second quarter of 2014, the Partnership entered into financial swap contracts on a notional amount of 7,131,000 gallons of propane with maturity dates ranging from June 2014 through March 2016.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of variable-rate borrowings under its revolving credit facilities. Management believes it is prudent to limit the variability of a portion of the Partnership's interest payments. To meet this objective, the Partnership entered into interest rate swap agreements to manage the fluctuation in cash flows resulting from interest rate risk on a portion of its debt with a variable-rate component. These swaps ultimately change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, the Partnership receives variable interest rate payments and makes fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of debt that is swapped.
Credit Risk. By using derivative instruments to economically hedge exposure to changes in commodity prices and interest rates, the Partnership exposes itself to counterparty credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative is negative, the Partnership owes the counterparty and, therefore, it does not possess credit risk. The Partnership minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties. The Partnership has entered into Master International Swap Dealers Association ("IDSA") Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.
Fair Value of Derivative Instruments. The Partnership measures derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize primarily observable ("level 2") inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of the Partnership's derivative contracts are designated as hedging instruments.
F-27
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
8. Derivative Instruments (Continued)
The following table summarizes the fair values of the Partnership's derivative contracts included in the condensed consolidated balance sheets as of December 31, 2013 and June 30, 2014.
| |
|
Asset Derivatives | Liability Derivatives | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Derivatives not designated as hedging contracts: |
Balance Sheet Location | December 31, 2013 |
June 30, 2014 |
December 31, 2013 |
June 30, 2014 |
||||||||||
Commodity swap contracts |
Prepaid expenses and other current assets | $ | 498 | $ | — | $ | — | $ | — | ||||||
Commodity swap contracts |
Accrued liabilities | — | — | — | (31 | ) | |||||||||
Commodity swap contracts |
Other long-term liabilities | — | — | — | (28 | ) | |||||||||
Interest rate swap contracts |
Accrued liabilities | — | — | (200 | ) | (251 | ) | ||||||||
Interest rate swap contracts |
Other long-term liabilities | — | — | (4 | ) | (15 | ) | ||||||||
As of December 31, 2013 and June 30, 2014, the Partnership presented the fair value of derivative contracts on a gross basis on the condensed consolidated balance sheets. In the condensed consolidated statements of cash flows, the effects of settlements of derivative instruments are classified as operating activities, consistent with the related transactions.
The following table summarize the amounts recognized with respect to the Partnership's derivative instruments within the condensed consolidated statements of operations.
| |
|
Amount of Gain/(Loss) Recognized in Income on Derivatives |
|||||||
|---|---|---|---|---|---|---|---|---|---|
Derivatives not designated as hedging contracts: |
Location of Gain/(Loss) Recognized in Income on Derivatives |
June 30, 2013 | June 30, 2014 | ||||||
Commodity derivatives |
Cost of sales | $ | (610 | ) | $ | 32 | |||
Interest rate swaps |
Interest expense | 76 | (195 | ) | |||||
9. Partners' Capital
Common Units. On February 12, 2014, the Partnership issued 363,636 Class A Common Units to Lonestar Midstream Holdings, LLC ("Lonestar"), an affiliate of ArcLight for total net proceeds of $8,000,000.
Series D Preferred Units. On March 28, 2014 (the "Issue Date"), the Partnership authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the "Series D Preferred Units") for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the "Subscription Agreement") by and among the Partnership, GP II, and Lonestar. This transaction resulted in proceeds to the Partnership of $40,000,000.
The Series D Preferred Units are a new class of voting equity security that ranks senior to all of the Partnership's other classes of equity securities with the respect to distribution rights and rights upon liquidation. The Series D Preferred Units have voting rights identical to the voting rights of the Partnership's Class A Common Units and will vote with the Partnership's common units as a single class, such that each Series D Preferred Unit (including each Series D Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series D Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.
F-28
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
9. Partners' Capital (Continued)
Each Series D Preferred Unit (including Series D Paid-in-kind ("PIK") Units issued as in-kind distributions) earns a cumulative distribution that is payable in either cash or Series D PIK Units as described below. The distribution rate for any such unit is (A) with respect to any distribution for the four consecutive quarters commencing with the quarter ended June 30, 2014, an amount equal to the greater of (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit is such unit had been converted into a common unit of the Partnership of the date of determination and (ii) $0.66, and (B) with respect to any distribution for any quarterly period after the quarter ending March 31, 2015, (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.825. If the Partnership does not have sufficient available cash to make cash distributions with respect to the common units, the Partnership may pay all of any portion of the Series D Distribution in-kind during each quarter commencing on the Issue Date and ending on March 31, 2015. The amount of Series D PIK Units is determined based on any unpaid cash distribution divided by $22.00.
The Series D Preferred Units (including Series D PIK Units issued as in-kind distributions) are convertible into common units of the Partnership on a one-for-one basis by Lonestar at any time after December 31, 2014. The Partnership may redeem the Series D Preferred Units (A) at any time prior to the Partnership's initial public offering of its common units or (B) during the period commencing on the Issue Date and ending on April 1, 2015, whichever is later, in each case at a price of $22.00 per Series D Preferred Unit, subject to adjustment pursuant to the provisions of the Partnership Agreement.
10. Commitments and Contingencies
Legal Matters. The Partnership is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Partnership's condensed consolidated financial position, results of operations, or liquidity.
Environmental Matters. The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Partnerships activities. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Partnership accounts for environmental contingencies in accordance with the ASC Topic 410 related to accounting for contingencies. Environmental expenditures that relate to current operations
F-29
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
10. Commitments and Contingencies (Continued)
are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean- ups are probable, and the costs can be reasonably estimated. At December 31, 2013 and June 30, 2014, the Partnership had no material environmental matters.
Refined Products Terminals. In the third quarter of 2014, the Partnership discovered that certain elements of the product measurement and quality control at its refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal could under-deliver refined products to its customers and consequently, recognize excessive gains on refined products generated through the terminal's normal terminal and storage process. The Partnership recognizes revenues for refined product gains as the products are sold at the terminal based on current market prices. The Partnership has undertaken procedures to improve and remediate its measurement and quality control processes to be in compliance with industry standards and regulations, and is in the process of discussing this matter with its customers and returning to them a certain amount of refined products. Because there are numerous elements inherent in the product measurement process that could affect the amount of refined product gains generated at the terminal, it is not practicable for the Partnership to accurately quantify the amount or discrete period of refined product gains previously recognized that were caused by these specific issues. However, the Partnership, using available operational data and certain management assumptions, has reasonably estimated the volume of refined products to be returned to its customers of approximately 24,000 barrels, which amounts to an estimated value of $2,700,000 as of June 30, 2014. Accordingly, the Partnership recorded this charge to operating expenses in the consolidated statement of operations for the six months ended June 30, 2014 and will update the estimated accrual each reporting period based on changes in estimate related to volumes returned, market prices and other changes. The Partnership intends to return the estimated refined products during the fourth quarter of 2014.
11. Reportable Segments
The Partnership's operations are located in the United States and are organized into four reportable segments: crude oil pipelines and storage; crude oil supply and logistics; refined products terminals and storage; and NGL distribution and sales.
Crude oil pipelines and storage. The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 40,000 barrels of storage capacity. The Partnership also operates a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.
Crude oil supply and logistics. The crude oil supply and logistics segment consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. The Partnership conducts
F-30
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
11. Reportable Segments (Continued)
crude oil supply activities by purchasing crude oil for its own account from producers, aggregators and traders and selling crude oil to traders and refiners. The Partnership also owns a fleet of crude oil gathering and transportation trucks operating in and around high-growth drilling areas such as the Midcontinent, the Eagle Ford shale, and the Permian Basin. As described in Note 3, the disposition of the Bakken Business impacts the crude oil supply and logistics segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information tables. Accordingly, the Partnership has recast the segment information.
Refined products terminals and storage. The refined products terminals and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal has storage capacity of 550,000 barrels from 11 tanks and is primarily served by the refined products pipeline operated by Enterprise TE Products Pipeline Company LLC. The Caddo Mills terminal has storage capacity of 770,000 barrels from 10 tanks and is served by the Explorer Pipeline.
NGL distribution and sales. The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 48 states through a network of over 17,700 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in six states in the southwest region of the U.S., the Partnership sells NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. The Partnership also owns a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.
Corporate and other. Corporate and other includes general partnership expenses associated with managing all of the Partnership's reportable segments.
The Partnership accounts for intersegment revenues as if the revenues were to third parties.
The Partnership's chief operating decision maker evaluates the segments' operating performance based on Adjusted EBITDA. Adjusted EBITDA is defined by the Partnership as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring.
F-31
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
11. Reportable Segments (Continued)
The following tables reflect certain financial data for each reportable segment for the six months ended June 30, 2013 and 2014.
| |
Six months ended June 30, |
||||||
|---|---|---|---|---|---|---|---|
| |
2013 | 2014 | |||||
External Revenues: |
|||||||
Crude oil pipelines and storage |
$ | 7,200 | $ | 40,425 | |||
Crude oil supply and logistics |
878,273 | 704,003 | |||||
Refined products terminals and storage |
13,123 | 13,889 | |||||
NGL distribution and sales |
89,208 | 107,500 | |||||
| | | | | | | | |
Total revenues |
$ | 987,804 | $ | 865,817 | |||
| | | | | | | | |
| | | | | | | | |
Intersegment Revenues: |
|||||||
Crude oil pipelines and storage |
$ | — | $ | — | |||
Crude oil supply and logistics |
— | 25,227 | |||||
Refined products terminals and storage |
— | — | |||||
NGL distribution and sales |
— | — | |||||
Intersegment eliminations |
— | (25,227 | ) | ||||
| | | | | | | | |
Total intersegment revenues |
$ | — | $ | — | |||
| | | | | | | | |
| | | | | | | | |
Cost of Sales, excluding depreciation and amortization: |
|||||||
Crude oil pipelines and storage |
$ | — | $ | 28,058 | |||
Crude oil supply and logistics |
865,035 | 722,756 | |||||
Refined products terminals and storage |
2,873 | 4,083 | |||||
NGL distribution and sales |
50,958 | 67,594 | |||||
Intersegment eliminations |
— | (25,227 | ) | ||||
Amounts not included in segment Adjusted EBITDA |
91 | 929 | |||||
| | | | | | | | |
Total cost of sales, excluding depreciation and amortization |
$ | 918,957 | $ | 798,193 | |||
| | | | | | | | |
| | | | | | | | |
Operating Expense: |
|||||||
Crude oil pipelines and storage |
$ | 1,230 | $ | 1,935 | |||
Crude oil supply and logistics |
3,424 | 3,117 | |||||
Refined products terminals and storage |
1,216 | 4,000 | |||||
NGL distribution and sales |
21,964 | 25,746 | |||||
Amounts not included in segment Adjusted EBITDA |
368 | 468 | |||||
| | | | | | | | |
Total operating expenses |
$ | 28,202 | $ | 35,266 | |||
| | | | | | | | |
| | | | | | | | |
Adjusted EBITDA: |
|||||||
Crude oil pipelines and storage |
$ | 6,023 | $ | 10,146 | |||
Crude oil supply and logistics |
8,496 | 1,658 | |||||
Refined products terminals and storage |
8,827 | 5,141 | |||||
NGL distribution and sales |
11,150 | 7,646 | |||||
| | | | | | | | |
Total Adjusted EBITDA from reportable segments |
$ | 34,496 | $ | 24,591 | |||
| | | | | | | | |
| | | | | | | | |
F-32
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
11. Reportable Segments (Continued)
A reconciliation of total Adjusted EBITDA from reportable segments to net income (loss) from continuing operations is included in the table below.
| |
Six months ended June 30, | ||||||
|---|---|---|---|---|---|---|---|
| |
2013 | 2014 | |||||
Total Adjusted EBITDA from reportable segments |
$ | 34,496 | $ | 24,591 | |||
Other expenses not allocated to reportable segments |
(12,218 | ) | (13,536 | ) | |||
Depreciation and amortization |
(15,186 | ) | (20,165 | ) | |||
Interest expense |
(3,815 | ) | (5,551 | ) | |||
Loss on extinguishment of debt |
— | (1,634 | ) | ||||
Income tax expense |
(305 | ) | (156 | ) | |||
Loss on disposal of assets |
(998 | ) | (661 | ) | |||
Unit-based compensation |
(371 | ) | (584 | ) | |||
Total gain on commodity derivatives |
(610 | ) | 32 | ||||
Net cash (receipts) payments for commodity derivatives settled during the period |
518 | (588 | ) | ||||
Transaction costs and other non-cash items |
(1,288 | ) | (932 | ) | |||
| | | | | | | | |
Net income (loss) from continuing operations |
$ | 223 | $ | (19,184 | ) | ||
| | | | | | | | |
| | | | | | | | |
Total assets from the Partnership's reportable segments as of December 31, 2013 and June 30, 2014 were as follows:
| |
December 31, 2013 |
June 30, 2014 |
|||||
|---|---|---|---|---|---|---|---|
Crude oil pipelines and storage |
$ | 313,580 | $ | 321,153 | |||
Crude oil supply and logistics |
208,420 | 199,509 | |||||
Refined products terminals and storage |
132,325 | 131,077 | |||||
NGL distribution and sales |
178,450 | 170,072 | |||||
Corporate and other |
10,627 | 20,661 | |||||
| | | | | | | | |
Total assets |
$ | 843,402 | $ | 842,472 | |||
| | | | | | | | |
| | | | | | | | |
12. Related Party Transactions
The Partnership entered into transactions with CAMS Bluewire, an entity in which ArcLight holds a non-controlling interest. CAMS Bluewire provides IT support for the Partnership. For the six months ended June 30, 2013 and 2014, the Partnership paid $441,000 and $216,000, respectively, for IT support and consulting services, and for the purchases of IT equipment which are included in operating expense, general and administrative and property, plant and equipment, net in the condensed consolidated statements of operations and the condensed consolidated balance sheets. The total amounts due to CAMS Bluewire as of December 31, 2013 and June 30, 2014 was $38,000 and $31,000, respectively.
F-33
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular amounts, except per unit data, are in thousands)
(Unaudited)
12. Related Party Transactions (Continued)
As a result of the acquisition of ATT in November, 2012, Truman Arnold Companies ("TAC") owns certain Class C common units in the Partnership. In addition, Mr. Greg Arnold, President and CEO of TAC, is also a director of the Partnership. The Partnership's refined products terminals and storage segment sells refined products to TAC. For the six months ended June 30, 2013 and 2014, the Partnership's revenue from TAC was $9,861,000 and $8,380,000, respectively. As of December 31, 2013 and June 30, 2014, the Partnership had trade receivable balances due from TAC of $1,048,000 and $273,000, respectively, which are included in receivables from related parties on the condensed consolidated balance sheets.
In 2013, the Partnership's NGL distribution and sales segment began purchasing refined products from TAC. The Partnership did not purchase refined products from TAC during the six months ended June 30, 2013 and 2014. The total amount due to TAC as of December 31, 2013 is $119,000.
Beginning in July 2013, the Partnership does not have any employees. The employees supporting the operations of the Partnership are employees of GP II, and as such, the Partnership funds GP II for payroll and other payroll-related expenses incurred by the Partnership. As of December 31, 2013 and June 30, 2014 the Partnership had a receivable balance due from GP II of $1,611,000 and a payable balance due to GP II of $22,000, respectively, as a result of the timing of payroll funding, which is included in receivables from related parties on the condensed consolidated balance sheets.
The Partnership performs certain management services for JP Development. The Partnership receives a monthly fee of $50,000 for these services which reduced the general and administrative expenses in the condensed consolidated statements of operations by $300,000 for each of the six months ended June 30, 2013 and 2014.
JP Development has a pipeline transportation business that provides crude oil pipeline transportation services to the Partnership's crude oil supply and logistics segment. As a result of utilizing JP Development's pipeline transportation services, the Partnership incurred pipeline tariff fees of $7,257,000 and $4,953,000, which is included in costs of sales on the condensed consolidated statements of operations for the six months ended June 30, 2013 and 2014, respectively.
13. Subsequent Events
The Partnership has evaluated subsequent events through September 8, 2014, the date of which the condensed consolidated financial statements were available to be issued, and there were no additional disclosures required.
F-34
Report of Independent Registered Public Accounting Firm
To
the Partners and Unitholders of
JP Energy Partners LP:
We have audited the accompanying consolidated balance sheets of JP Energy Partners LP and its subsidiaries (the "Partnership") as of December 31, 2013 and 2012, and the related consolidated statements of operations, partners' capital and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of JP Energy Partners LP and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Partnership has restated its 2012 financial statements to correct errors.
/s/
PricewaterhouseCoopers LLP
Dallas, Texas
May 7,
2014, except for the effects of
discontinued operations discussed
in Note 4 to the consolidated
financial statements, as to which the
date is September 8, 2014
F-35
CONSOLIDATED BALANCE SHEETS
(in thousands)
| |
December 31, 2012 |
December 31, 2013 |
|||||
|---|---|---|---|---|---|---|---|
| |
(Restated and Recast) |
|
|||||
ASSETS |
|||||||
Current assets |
|||||||
Cash and cash equivalents |
$ | 10,099 | $ | 3,234 | |||
Accounts receivable, net |
80,551 | 122,919 | |||||
Receivables from related parties |
1,794 | 2,742 | |||||
Inventory |
19,635 | 38,579 | |||||
Prepaid expenses and other current assets |
7,500 | 4,991 | |||||
| | | | | | | | |
Total current assets |
119,579 | 172,465 | |||||
| | | | | | | | |
Non-current assets |
|||||||
Property, plant and equipment, net |
191,864 | 238,093 | |||||
Goodwill |
132,578 | 250,705 | |||||
Intangible assets, net |
113,736 | 175,101 | |||||
Deferred financing costs and other assets, net |
4,367 | 7,038 | |||||
| | | | | | | | |
Total non-current assets |
442,545 | 670,937 | |||||
| | | | | | | | |
Total Assets |
$ | 562,124 | $ | 843,402 | |||
| | | | | | | | |
| | | | | | | | |
LIABILITIES AND PARTNERS' CAPITAL |
|||||||
Current liabilities |
|||||||
Accounts payable |
$ | 56,899 | $ | 95,765 | |||
Payables to related parties |
— | 1,274 | |||||
Accrued liabilities |
16,076 | 22,748 | |||||
Capital leases and short-term debt |
3,932 | 538 | |||||
Customer deposits and advances |
2,705 | 2,722 | |||||
Current portion of long-term debt |
2,973 | 698 | |||||
| | | | | | | | |
Total current liabilities |
82,585 | 123,745 | |||||
Non-current liabilities |
|||||||
Long-term debt |
164,766 | 183,148 | |||||
Note payable to related party |
— | 1,000 | |||||
Other long-term liabilities |
620 | 2,116 | |||||
| | | | | | | | |
Total Liabilities |
247,971 | 310,009 | |||||
| | | | | | | | |
Commitments and contingencies (Note 16) |
|||||||
Partners' capital |
|||||||
Predecessor capital |
51,138 | 304,065 | |||||
Preferred units |
20,966 | — | |||||
General partner interest |
404 | 404 | |||||
Class A common units (6,868,004 and 8,004,368 units authorized, issued and outstanding at December 31, 2012 and 2013, respectively) |
144,534 | 140,752 | |||||
Class B common units (1,180,008 and 1,244,508 units authorized, 1,153,505 and 1,206,844 units issued and outstanding at December 31, 2012 and 2013, respectively) |
14,247 | 11,366 | |||||
Class C common units (3,166,667 and 3,254,781 shares authorized, issued and outstanding at of December 31, 2012 and 2013, respectively) |
82,864 | 76,806 | |||||
| | | | | | | | |
Total partners' capital |
314,153 | 533,393 | |||||
| | | | | | | | |
Total Liabilities and Partners' Capital |
$ | 562,124 | $ | 843,402 | |||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to consolidated financial statements
F-36
JP ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except unit and per unit data)
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
(Restated and Recast) |
|||||||||
REVENUES |
||||||||||
Crude oil sales |
$ | — | $ | 290,253 | $ | 1,875,392 | ||||
Gathering, transportation and storage fees |
— | 8,243 | 24,146 | |||||||
NGL and refined product sales (including sales to related parties of $1,719 and $12,343 in 2012 and 2013, respectively) |
63,190 | 119,116 | 178,588 | |||||||
Refined products terminals and storage fees (including sales to related parties of $25 and $2,130 in 2012 and 2013, respectively) |
— | 984 | 12,309 | |||||||
Other revenues |
3,966 | 8,985 | 11,798 | |||||||
| | | | | | | | | | | |
Total revenues |
67,156 | 427,581 | 2,102,233 | |||||||
| | | | | | | | | | | |
COSTS AND EXPENSES |
||||||||||
Cost of sales, excluding depreciation and amortization |
49,048 | 368,791 | 1,964,631 | |||||||
Operating expense |
9,584 | 28,640 | 61,925 | |||||||
General and administrative |
6,053 | 20,983 | 45,284 | |||||||
Depreciation and amortization |
2,841 | 13,856 | 33,345 | |||||||
Loss on disposal of assets, net |
68 | 1,142 | 1,492 | |||||||
| | | | | | | | | | | |
Total costs and expenses |
67,594 | 433,412 | 2,106,677 | |||||||
| | | | | | | | | | | |
OPERATING LOSS |
(438 | ) | (5,831 | ) | (4,444 | ) | ||||
OTHER INCOME (EXPENSE) |
||||||||||
Interest expense |
(633 | ) | (3,405 | ) | (9,075 | ) | ||||
Loss on extinguishment of debt |
(95 | ) | (497 | ) | — | |||||
Other income, net |
— | 247 | 688 | |||||||
| | | | | | | | | | | |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
(1,166 | ) | (9,486 | ) | (12,831 | ) | ||||
| | | | | | | | | | | |
| | | | | | | | | | | |
Income tax expense |
(35 |
) |
(222 |
) |
(208 |
) |
||||
| | | | | | | | | | | |
LOSS FROM CONTINUING OPERATIONS |
$ | (1,201 | ) | $ | (9,708 | ) | $ | (13,039 | ) | |
INCOME (LOSS) FROM DISCONTINUED OPERATIONS |
— | 1,320 | (1,182 | ) | ||||||
| | | | | | | | | | | |
NET LOSS |
$ | (1,201 | ) | $ | (8,388 | ) | $ | (14,221 | ) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Net loss attributable to preferred unitholders |
$ | 93 | $ | 1,348 | $ | 602 | ||||
Net (income) loss attributable to predecessor capital |
— | 1,387 | (5,940 | ) | ||||||
General partner's interest |
— | — | — | |||||||
| | | | | | | | | | | |
Net loss attributable to common unitholders |
$ | (1,108 | ) | $ | (5,653 | ) | $ | (19,559 | ) | |
| | | | | | | | | | | |
Basic and diluted loss per common unit |
||||||||||
Weighted average number of common units outstanding |
942,996 | 4,686,632 | 11,734,509 | |||||||
Basic and diluted loss per common unit from continuing operations |
$ | (1.17 | ) | $ | (1.49 | ) | $ | (1.57 | ) | |
Basic and diluted income (loss) per common unit from discontinued operations |
$ | — | $ | 0.28 | $ | (0.10 | ) | |||
Basic and diluted loss per common unit |
$ | (1.17 | ) | $ | (1.21 | ) | $ | (1.67 | ) | |
Distribution per common unit |
$ | 1.00 | $ | 2.00 | $ | 1.00 | ||||
See accompanying notes to consolidated financial statements
F-37
JP ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(in thousands, except unit data)
| |
Units | |||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Preferred | General Partner |
Common | Class A Common |
Class B Common |
Class C Common |
Total | |||||||||||||||
Balance—January 1, 2011 |
— | 45 | 642,000 | — | — | — | 642,045 | |||||||||||||||
Issuance of Common Units |
— |
— |
271,975 |
— |
— |
— |
271,975 |
|||||||||||||||
Issuance of Class A Common Units |
— | — | — | 49,821 | — | — | 49,821 | |||||||||||||||
Conversion of Common Units to Class B Common Units |
— | — | (913,975 | ) | — | 913,975 | — | — | ||||||||||||||
Issuance of Class B Common Units |
— | — | — | — | 78,030 | — | 78,030 | |||||||||||||||
Issuance of Preferred Units |
1,136,364 | — | — | — | — | — | 1,136,364 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2011 |
1,136,364 | 45 | — | 49,821 | 992,005 | — | 2,178,235 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Issuance of Class A Common Units |
— | — | — | 6,818,183 | — | — | 6,818,183 | |||||||||||||||
Issuance of Class B Common Units |
— | — | — | — | 161,500 | — | 161,500 | |||||||||||||||
Issuance of Class C Common Units |
— | — | — | — | — | 3,166,667 | 3,166,667 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2012 |
1,136,364 | 45 | — | 6,868,004 | 1,153,505 | 3,166,667 | 12,324,585 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Issuance of Class B Common Units, net of forfeitures |
— | — | — | — | 53,339 | — | 53,339 | |||||||||||||||
Issuance of Class C Common Units |
— | — | — | — | — | 88,114 | 88,114 | |||||||||||||||
Conversion of Preferred Units to Class A Common Units |
(1,136,364 | ) | — | — | 1,136,364 | — | — | — | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2013 |
— | 45 | — | 8,004,368 | 1,206,844 | 3,254,781 | 12,466,038 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements
F-38
JP ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (Continued)
(in thousands, except unit data)
| |
Preferred | General Partner |
Predecessor Capital |
Common | Class A Common |
Class B Common |
Class C Common |
Total | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance—January 1, 2011 |
$ | — | $ | (8 | ) | $ | — | $ | 10,223 | $ | — | $ | — | $ | — | $ | 10,215 | ||||||||
Issuance of Common Units |
— |
— |
— |
5,440 |
— |
— |
— |
5,440 |
|||||||||||||||||
Issuance of Class A Common Units |
— | — | — | — | 1,096 | — | — | 1,096 | |||||||||||||||||
Conversion of Common Units to Class B Common Units |
— | — | — | (14,862 | ) | — | 14,862 | — | — | ||||||||||||||||
Issuance of Class B Common Units |
— | — | — | — | — | 1,717 | — | 1,717 | |||||||||||||||||
Issuance of Preferred Units |
25,000 | — | — | — | — | — | — | 25,000 | |||||||||||||||||
Distributions to unitholders |
— | — | — | (801 | ) | — | — | — | (801 | ) | |||||||||||||||
Net loss |
(93 | ) | — | — | — | (1 | ) | (1,107 | ) | — | (1,201 | ) | |||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2011 |
$ | 24,907 | $ | (8 | ) | $ | — | $ | — | $ | 1,095 | $ | 15,472 | $ | — | $ | 41,466 | ||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Contribution from the Predecessor |
— | — | 52,525 | — | — | — | — | 52,525 | |||||||||||||||||
Issuance of Class A Common Units |
— | — | — | — | 150,000 | — | — | 150,000 | |||||||||||||||||
Issuance of Class B Common Units |
— | — | — | — | — | 100 | — | 100 | |||||||||||||||||
Issuance of Class C Common Units |
— | — | — | — | — | — | 83,778 | 83,778 | |||||||||||||||||
Unit-based compensation |
— | 412 | — | — | 63 | 2,010 | — | 2,485 | |||||||||||||||||
Distributions to unitholders |
(2,593 | ) | — | — | — | (2,922 | ) | (2,037 | ) | (261 | ) | (7,813 | ) | ||||||||||||
Net loss |
(1,348 | ) | — | (1,387 | ) | — | (3,702 | ) | (1,298 | ) | (653 | ) | (8,388 | ) | |||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2012—Restated and Recast |
$ | 20,966 | $ | 404 | $ | 51,138 | $ | — | $ | 144,534 | $ | 14,247 | $ | 82,864 | $ | 314,153 | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Contribution from the Predecessor |
— | — | 246,987 | — | — | — | — | 246,987 | |||||||||||||||||
Issuance of Class B Common Units, net of forfeitures and tax withholding |
— | — | — | — | — | (164 | ) | — | (164 | ) | |||||||||||||||
Issuance of Class C Common Units to a related party |
— | — | — | — | — | — | 3,128 | 3,128 | |||||||||||||||||
Conversion of Preferred Units to Class A Common Units |
(18,660 | ) | — | — | — | 18,660 | — | — | — | ||||||||||||||||
Unit-based compensation |
— | — | — | — | — | 948 | — | 948 | |||||||||||||||||
Distributions to unitholders |
(1,704 | ) | — | — | — | (10,085 | ) | (1,683 | ) | (3,966 | ) | (17,438 | ) | ||||||||||||
Net income (loss) |
(602 | ) | — | 5,940 | — | (12,357 | ) | (1,982 | ) | (5,220 | ) | (14,221 | ) | ||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance—December 31, 2013 |
$ | — | $ | 404 | $ | 304,065 | $ | — | $ | 140,752 | $ | 11,366 | $ | 76,806 | $ | 533,393 | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements
F-39
JP ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
|
(Restated and Recast) |
|
|||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||
Net loss |
$ | (1,201 | ) | $ | (8,388 | ) | $ | (14,221 | ) | |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: |
||||||||||
Depreciation and amortization |
2,841 | 15,126 | 36,195 | |||||||
Derivative valuation changes |
— | (1,330 | ) | (1,162 | ) | |||||
Amortization of deferred financing costs |
30 | 490 | 1,103 | |||||||
Unit-based compensation expenses |
— | 2,485 | 948 | |||||||
Loss on disposal of assets |
68 | 1,142 | 1,492 | |||||||
Bad debt expense |
160 | 826 | 855 | |||||||
Loss on extinguishment of debt |
95 | 497 | — | |||||||
Other non-cash items |
69 | 131 | (378 | ) | ||||||
Changes in working capital, net of acquired assets and liabilities: |
||||||||||
Accounts receivable |
(4,055 | ) | (23,491 | ) | (26,583 | ) | ||||
Receivables from related parties |
— | (1,794 | ) | (948 | ) | |||||
Inventory |
(149 | ) | (5,583 | ) | (18,646 | ) | ||||
Prepaid expenses and other current assets |
753 | 529 | 4,340 | |||||||
Accounts payable and other accrued liabilities |
(4,627 | ) | 11,489 | 30,106 | ||||||
Payables to related parties |
— | — | 1,274 | |||||||
Customer deposits and advances |
121 | 881 | (493 | ) | ||||||
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES |
(5,895 | ) | (6,990 | ) | 13,882 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||
Capital expenditures |
(2,215 | ) | (21,032 | ) | (26,828 | ) | ||||
Acquisitions of businesses, net of cash acquired |
(25,543 | ) | (272,228 | ) | (1,003 | ) | ||||
Release of restricted cash |
800 | — | — | |||||||
Proceeds received from sale of assets |
98 | 926 | 96 | |||||||
NET CASH USED IN INVESTING ACTIVITIES |
(26,860 | ) | (292,334 | ) | (27,735 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||
Proceeds from revolving line of credit |
24,518 | 152,139 | 32,300 | |||||||
Payments on revolving line of credit |
(10,750 | ) | (10,000 | ) | (12,150 | ) | ||||
Proceeds from long-term debt |
— | 2,091 | — | |||||||
Proceeds from note payable to related party |
— | — | 1,000 | |||||||
Payments on long-term debt |
(9,881 | ) | (1,286 | ) | (4,152 | ) | ||||
Payments on capital leases |
(156 | ) | (202 | ) | (164 | ) | ||||
Change in cash overdraft |
— | — | 386 | |||||||
Payments on financed insurance premium |
(597 | ) | (1,581 | ) | (5,127 | ) | ||||
Debt issuance costs |
(760 | ) | (3,244 | ) | (980 | ) | ||||
Distributions to unitholders |
(801 | ) | (7,813 | ) | (17,438 | ) | ||||
Issuance of units |
33,252 | 150,100 | 3,128 | |||||||
Contributions from the Predecessor |
— | 24,787 | 12,040 | |||||||
Other |
— | — | (1,855 | ) | ||||||
NET CASH PROVIDED BY FINANCING ACTIVITIES |
34,825 | 304,991 | 6,988 | |||||||
Net change in cash and cash equivalents |
2,070 | 5,667 | (6,865 | ) | ||||||
Cash and cash equivalents, beginning of year |
2,362 | 4,432 | 10,099 | |||||||
Cash and cash equivalents, end of year |
$ | 4,432 | $ | 10,099 | $ | 3,234 | ||||
SUPPLEMENTAL DISCLOSURES: |
||||||||||
Cash paid for interest |
$ | 646 | $ | 1,757 | $ | 7,063 | ||||
Cash paid for taxes |
— | 35 | 106 | |||||||
Non-cash investing and financing transactions: |
||||||||||
Accrued capital expenditures |
$ | — | $ | 1,270 | $ | 977 | ||||
Debt funded portion of acquisition |
— | 598 | — | |||||||
Acquistitions funded by issuance of units |
— | 83,778 | — | |||||||
Assets acquired under capital lease |
288 | 276 | 13 | |||||||
Financed insurance premium |
983 | 4,608 | 1,420 | |||||||
Payable due to seller |
— | 1,003 | — | |||||||
See accompanying notes to consolidated financial statements
F-40
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except unit and per unit data, are in
thousands)
1. Business and Basis of Presentation
Business. The consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries ("JPE" or the "Partnership"). The Partnership was formed in May 2010 by members of management and was further capitalized in June 2011 by ArcLight Capital Partners, LLC ("ArcLight") to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership's operations currently consist of: (i) crude oil pipelines and storage; (ii) crude oil supply and logistics; (iii) refined products terminals and storage; and (iv) natural gas liquid ("NGL") distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. JP Energy GP II LLC ("GP II") is the Partnership's general partner.
JP Development. On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership ("JP Development"), for the express purpose of supporting JPE's growth. Since its formation, JP Development has acquired a portfolio of midstream assets that have been developed for potential future sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development made the following acquisitions since its formation in July 2012:
- •
- On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company
("Parnon Gathering"), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition,
Parnon Gathering LLC was renamed to JP Energy Marketing LLC ("JPEM").
- •
- On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH
Propane, LLC, an Arkansas limited liability company ("BMH"), which is engaged in the retail and wholesale propane and refined fuel distribution business.
- •
- On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil
Field Services, Inc., a Texas Corporation ("AOFS"), which is engaged in the crude oil trucking business.
- •
- On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability
("Wildcat Permian") that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company ("JP Permian"). JP Permian is engaged in the transportation of crude oil by
pipeline.
- •
- On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development ("JP Liquids"), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation ("Highway Pipeline"), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.
Common Control Acquisition between JPE and JP Development. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, the Partnership acquired (i) certain marketing and trucking businesses of JPEM (the "Parnon Gathering Assets"), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the "Dropdown Assets") from JP Development for an aggregate purchase price of approximately $319.1 million (the "Common
F-41
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
1. Business and Basis of Presentation (Continued)
Control Acquisition"), which comprised of 12,561,934 JPE Class A Common Units and $52 million cash. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility.
Basis of Presentation. Because JPE and JP Development are under common control, JPE is required under generally accepted accounting principles in the United States ("GAAP") to account for this Common Control Acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, JPE reflected in its balance sheet the Dropdown Assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. JPE also retrospectively recast its financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).
The historical assets and liabilities and the operating results of the Dropdown Assets have been "carved out" from JP Development's consolidated financial statements using JP Development's historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. JPE's recast historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification. Management believes the assumptions underlying the combined financial statements are reasonable. However, the combined financial statements do not fully reflect what the Partnership, including the Dropdown Assets' balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under JPE management during the periods presented. As a result, historical financial information is not necessarily indicative of what the Partnership's balance sheet, results of operations, and cash flows will be in the future.
JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the years ended December 31, 2012 and 2013. The total net effect of the deemed contributions is reflected as Contribution from the Predecessor in the statements of cash flows as a financing activity. The net balances due to JPE from the Dropdown Assets will be settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.
The "predecessor capital" included in Partners' Capital represents JP Development's net investment in the Dropdown Assets, which includes the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development. Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled and, as a result, were considered deemed contributions or distributions and are included in JP Development's net investment.
F-42
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
1. Business and Basis of Presentation (Continued)
Net income (loss) attributable to the Dropdown Assets prior to the Partnership's acquisition of such assets was not available for distribution to the Partnership's unitholders. Therefore, this income (loss) was not allocated to the limited partners for the purpose of calculating net loss per common unit; instead, the income (loss) was allocated to predecessor capital.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.
Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation.
Use of Estimates. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Cash and Cash Equivalents. The Partnership considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Bank overdrafts that do not meet the right of offset criteria are recorded in capital leases and short-term debt in the consolidated balance sheets.
Accounts Receivable. Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the consolidated statements of operations. The allowance for doubtful accounts was $691,000 and $1,207,000 as of December 31, 2012 and 2013, respectively. Bad debt expense for the years ended December 31, 2011, 2012 and 2013 was $160,000, $826,000 and $855,000, respectively.
Inventory. Inventory is mainly comprised of crude oil, NGLs, refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. Cost of crude oil, NGLs and refined products inventory is determined using the first-in, first-out (FIFO) method. Cost of propane cylinders is determined using the weighted average method.
Prepaid Expenses and Other Current Assets. Prepaid expenses primarily relate to prepaid insurance premiums, which totaled $4,235,000 and $697,000 at December 31, 2012 and 2013, respectively.
Derivative Instruments and Hedging Activities. The Partnership recognizes all derivative instruments as either assets or liabilities on the balance sheet at their respective fair values. The Partnership did not have any derivatives designated in hedging relationships during the three years ended December 31, 2013. Therefore, the change in the fair value of the derivative asset or liability is reflected in net loss on the consolidated statements of operations. Cash flows from derivatives settled are reported as cash
F-43
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
flow from operating activities, in the same category as the cash flows from the items being economically hedged.
The Partnership is also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction, or, upon acquisition, the fair value of the assets acquired. Maintenance and repairs are charged to operating expense and any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the account, and any resulting gain or loss is recognized within the consolidated statements of operations.
The Partnership accounts for asset retirement obligations by recognizing on its balance sheet the net present value of any legally binding obligation to remove or remediate tangible long-lived assets, such as requirements to dispose of equipment. The Partnership records a liability for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:
Buildings |
20 - 30 years | |
Leasehold improvements |
Various* | |
Transportation equipment |
5 - 15 years | |
Propane tanks and cylinders |
2 - 20 years | |
Bulk storage tanks |
15 - 20 years | |
Office furniture and fixture |
5 - 10 years | |
Other equipment |
3 - 5 years |
- *
- Depreciated over the shorter of the life of the leasehold improvement or the lease term.
Leases. The Partnership has both capital and operating leases. Classification is made at the inception of the lease. The classification of leases is based on the extent to which risks and rewards incidental to ownership of a leased asset lie with the lessor or the lessee.
Leased property meeting certain capital lease criteria is capitalized and the present value of the related lease payments is recorded as a liability. The present value of the minimum lease payments is calculated utilizing the lower of the Partnership's incremental borrowing rate or the lessor's interest rate implicit in the lease, if known by the Partnership. Depreciation of capitalized leased assets is computed utilizing the straight-line method over the shorter of the estimated useful life of the asset or the lease term and is included in depreciation and amortization in the Partnership's consolidated
F-44
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
statements of operations. However, if the lease meets the bargain purchase or transfer of ownership criteria, the asset shall be amortized in accordance with the Partnership's normal depreciation policy for owned assets.
Minimum rent payments under operating leases are recognized as an expense on a straight-line basis over the lease term, including any rent free periods.
Impairment of Long-Lived Assets. Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, the Partnership first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3).
Goodwill and Other Intangible Assets. The Partnership applies Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill and intangible assets. In accordance with these standards, the Partnership amortizes all definite lived intangible assets over their respective estimated useful lives, while goodwill has an indefinite life and is not amortized. The Partnership reviews finite lived intangible assets subject to amortization for impairment whenever events or circumstances indicate that the associated carrying amount may not be recoverable.
Goodwill is not amortized but is tested for impairment at least annually, or more frequently whenever a triggering event or change in circumstances occurs, at the reporting unit level. A reporting unit is the operating segment, or business one level below the operating segment if discrete financial information is prepared and regularly reviewed by segment management. The Partnership has the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership's most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.
No provision for impairment of goodwill or other intangible assets was recorded during 2011, 2012 or 2013.
Business Combinations. When a business is acquired, the Partnership allocates the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. The accounting standard for business combinations requires most identifiable assets, liabilities,
F-45
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs associated with the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt's stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite. Contingent consideration obligations are recorded at fair value on the date of acquisition, with increases or decreases in the fair value arising from changes in assumptions or discount periods recorded as contingent consideration expenses in the consolidated statement of operations in subsequent periods. The fair values assigned to tangible and intangible assets acquired and liabilities assumed, including contingent consideration, are based on management's estimates and assumptions, as well as other information compiled by management, including valuations that utilize customary valuation procedures and techniques.
When the Partnership acquires a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting. Under a common control acquisition, the assets and liabilities are recorded at the transferring entity's historical cost instead of reflecting the fair market value of assets and liabilities.
Deferred Financing Costs. Debt issuance costs are deferred and are recorded net of accumulated amortization on the consolidated balance sheets as deferred financing costs, and totaled $2,992,000 and $2,869,000 at December 31, 2012 and 2013, respectively. These costs are amortized over the terms of the related debt using the effective interest rate method for the notes payable and the straight-line method for the revolving credit facilities. As a result of the financing transactions discussed in Note 12, the Partnership wrote off $95,000 and $497,000 of deferred financing costs associated with the extinguishment of debt during the years ended December 31, 2011 and 2012, respectively, which is recorded in loss on extinguishment of debt on the consolidated statements of operations. Amortization of deferred financing costs is recorded in interest expense and totaled $30,000, $490,000 and $1,103,000 for the years ended December 31, 2011, 2012 and 2013, respectively.
Customer Deposits and Advances. Certain customers are offered a prepayment program which requires a customer to pay a fixed periodic amount or to otherwise prepay a portion of their anticipated product purchases. Customer prepayments in excess of associated billings are classified as customer deposits and advances on the consolidated balance sheets.
Revenue Recognition. The Partnership recognizes revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller's price to the buyer is fixed and determinable and collectability is reasonably assured.
Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the consolidated statements of operations.
Crude Oil Pipelines and Storage. The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, the Partnership enters into sale and purchase contracts with counterparties instead of
F-46
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
pipeline transportation agreements. In such cases, the Partnership assesses the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. Revenues from crude oil storage services are recognized when services are provided.
Crude Oil Supply and Logistics. The crude oil supply and logistics segment mainly generates revenues through crude oil sales. The Partnership enters into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contract the Partnership gathers, transports and blends different types of crude oil and eventually sells the blended crude oil to either the same counterparty or different counterparties. The Partnership accounts for such revenue arrangements on a gross basis. Occasionally, the Partnership enters into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. In addition, the Partnership also provides crude oil transportation services to third party customers. Revenues from these transportation services are recognized when the service is provided and when payment has either been received or collection is reasonably assured.
Refined Products Terminals and Storage. The Partnership generates fee-based revenues for terminal and storage services with longstanding customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes. Revenues are recognized as products are delivered by or stored by the Partnership when services are provided or when products are delivered and when payment has either been received or collection is reasonably assured.
NGLs Distributions and Sales. Revenues from the NGLs distributions and sales are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees which are recognized in the period that the products are delivered and when payment has either been received or collection is reasonably assured.
Operating expenses. Operating expenses primarily include personnel, vehicle, delivery, handling, office, selling, and other expenses related to the distribution, terminal and storage of products and related supplies.
Expenses associated with the delivery of products to customers (including vehicle expenses, expenses of delivery personnel and vehicle repair and maintenance) are classified as operating expenses in the consolidated statements of operations.
General and administrative expenses. General and administrative expenses primarily include wages and benefits and department related costs for human resources, legal, finance and accounting, administrative support and supply.
Fair value measurement. The Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Partnership determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant
F-47
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.
The fair value of the Partnership's derivatives (see Note 13) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The fair value of the Partnership's contingent liabilities (see Note 6) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). The Partnership does not have any other assets or liabilities measured at fair value on a recurring basis.
The Partnership's other financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and long term debt. The carrying value of the Partnership's trade and other receivables, accounts payable and accrued expenses approximates fair value due to their highly liquid nature, short term maturity, or competitive rates assigned to these financial instruments. The fair value of long-term debt approximates the carrying value as the underlying instruments bear interest at rates similar to current rates offered to the Partnership for debt with the same remaining maturities.
Concentration Risk. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Partnership has not experienced any losses related to these balances.
The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues from transactions with an external customer amounting to 10% or more of revenue are disclosed below, together with the identity of the reportable segment.
| |
|
Year Ended December 31, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
Customer
|
Reportable Segment | 2011 | 2012 | 2013 | ||||||||
Customer A |
Crude oil supply and logistics | — | 74,953 | 1,063,763 | ||||||||
Customer B |
Crude oil supply and logistics | — | — | 272,614 | ||||||||
Customer C |
Crude oil supply and logistics | — | 132,133 | * | ||||||||
- *
- Revenues are less than 10% of the total revenues during the period.
The Partnership is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.
F-48
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
2. Summary of Significant Accounting Policies (Continued)
Income Taxes. The Partnership is a limited partnership, and therefore is not directly subject to federal income taxes or most state income taxes. The taxable income (loss) of the Partnership will be included in the federal income tax returns filed by their individual partners. Accordingly, no federal income tax provision has been made in the consolidated financial statements of the Partnership since the income tax is an obligation of the partners. The Partnership is subject to Texas margin tax, which is reported in income tax expense in the consolidated statements of operations.
ASC Topic 740, "Income Taxes", requires the evaluation of tax positions taken or expected to be taken in the course of preparing the Partnership's state tax returns and disallows the recognition of tax positions not deemed to meet a "more-likely-than-not" threshold of being sustained by the applicable tax authority. The Partnership's management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership's policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.
Equity-Based Compensation. The Partnership accounts for equity-based compensation by recognizing the fair value of awards on the grant date or the date of modification, as applicable, into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required.
Comprehensive Income. For the years ended December 31, 2011, 2012 and 2013, comprehensive loss was equal to net loss.
3. Restatement and Recast of 2012 financial statements
Restatement. During 2013, the Partnership determined that its previously issued consolidated financial statements for the year ended December 31, 2012 contained errors. The Partnership evaluated those errors and determined that the impact of these errors was material to the previously issued consolidated financial statements. The Partnership concluded that it should restate its previously issued financial statements for the year ended December 31, 2012 to correct the previously identified errors as well as the correction of other previously identified immaterial errors. The Partnership also revised certain disclosures in Note 6, Note 7, Note 8, Note 9, Note 10 and Note 17 directly related to the restatement of these financial statements.
The following is a description of the nature of these errors for which the Partnership made correcting adjustments to its consolidated financial statements:
- 1)
- Acquisitions—The Partnership identified and corrected an error related to the estimated unbilled revenue of Heritage Propane Express, LLC at the date of acquisition. As a result, accounts receivable increased by $246,000, inventory increased by $33,000, property, plant and equipment decreased by $201,000 and goodwill decreased by $755,000. NGL distribution and sales revenue and cost of sales, excluding depreciation and amortization, decreased by $1,150,000 and $473,000, respectively. Additionally, the Partnership identified and corrected errors in the unbilled revenue of SemStream Arizona Propane, L.L.C. ("SemStream) at the acquisition date. As a result, accounts receivable increased $187,000, goodwill decreased $55,000 and accrued liabilities increased $133,000. The Partnership also identified and
F-49
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
3. Restatement and Recast of 2012 financial statements (Continued)
- 2)
- Cutoff—The Partnership identified and corrected errors from improper expense cutoff at
December 31, 2012 relating to cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses. The correction of these errors resulted in
increases in property, plant and equipment, deferred financing costs and other assets, accounts payable and accrued liabilities of $630,000, $25,000, $665,000 and $460,000, respectively, with
corresponding decreases in crude oil storage, gathering and transportation cost of sales, excluding depreciation and amortization and prepaid expenses and other current assets of $206,000 and $65,000,
respectively, and increases in NGL distribution and sales cost of sales, excluding depreciation and amortization, operating expenses and general and administrative of $99,000, $247,000 and $395,000,
respectively.
- 3)
- Fixed Assets—The Partnership identified and corrected errors resulting from the improper
capitalization of certain assets and the improper recognition of depreciation expense. The correction of these errors resulted in decreases of $1,908,000 in property, plant and equipment, $84,000 in
accounts payable, $607,000 in depreciation and amortization, and $45,000 in operating expenses and increases in inventory, goodwill, NGL distribution and sales cost of sales, excluding depreciation
and amortization, general and administrative and loss on disposal of assets of $501,000, $976,000, $169,000, $170,000 and $660,000, respectively.
- 4)
- Reclassification and Presentation—In addition to the correction of errors noted above, certain reclassifications were made to correct improperly or inconsistently presented amounts at December 31, 2012. The primary change in presentation was a reclassification of prepaid expenses and other current assets to customer deposits and advances of $188,000, a reclassification of prepaid expenses and other current assets to accounts receivable of $8,000, a reclassification of accrued liabilities to customer deposits and advances of $82,000 and a reclassification of general and administrative to operating expenses of $2,473,000. In addition, the Partnership corrected the presentation of certain out of pocket expenses that were reimbursed from a customer and the presentation of accrued legal expenses for which we were fully insured. The corrections resulted in an increase in crude oil storage, gathering and transportation revenue and cost of sales of $224,000, an increase in prepaid expenses and other current assets and accrued liabilities of $63,000 and an increase in deferred financing costs and other assets, net and other long-term liabilities of $150,000.
corrected errors in the initial purchase price allocation of fair value to the assets acquired and liabilities assumed in the SemStream acquisition. As a result, accounts payable decreased by $1,080,000, goodwill decreased by $801,000, prepaid expenses and other current assets decreased by $207,000, and accrued liabilities increased by $72,000.
Recast. As described in Note 1, as a result of the Common Control Acquisition, the Partnership has recast its financial statements for the year ended December 31, 2012, to include the assets and liabilities of the Dropdown Assets in its consolidated balance sheet as of December 31, 2012, and to include the operating results of the Dropdown Assets from August 3, 2012 (the date upon which common control began) in its consolidated statement of operations for the year then ended.
Discontinued Operations. As described in Note 4, due to the divestiture of a business in our crude oil supply and logistics segment, the Partnership has retrospectively adjusted the results of operations
F-50
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
3. Restatement and Recast of 2012 financial statements (Continued)
for the years ended December 31, 2012 and 2013, to report the business as discontinued operations, as required by GAAP. The Partnership did not own the business in 2011.
The tables below provide a reconciliation from the amounts previously reported in the Partnership's consolidated financial statements to the restated and recast amounts and indicate the category of the adjustments by reference to the above descriptions of the errors:
| |
Consolidated Balance Sheet As of December 31, 2012 |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
As Previously Reported |
Restatement Adjustments |
Description of Adjustments |
As Restated |
Recast Adjustments |
As Restated and Recast |
||||||||||||
ASSETS |
||||||||||||||||||
Current assets |
||||||||||||||||||
Cash and cash equivalents |
$ | 4,394 | $ | — | $ | 4,394 | $ | 5,705 | $ | 10,099 | ||||||||
Accounts receivable, net |
23,936 | 441 | (1) (4) | 24,377 | 56,174 | 80,551 | ||||||||||||
Receivables from related parties |
2,976 | — | 2,976 | (1,182 | ) | 1,794 | ||||||||||||
Inventory |
4,946 | 534 | (1) (3) | 5,480 | 14,155 | 19,635 | ||||||||||||
Prepaid expenses and other current assets |
7,786 | (405 | ) | (1) (2) (4) | 7,381 | 119 | 7,500 | |||||||||||
Total current assets |
44,038 | 570 | 44,608 | 74,971 | 119,579 | |||||||||||||
Non-current assets |
||||||||||||||||||
Property, plant and equipment, net |
178,290 | (1,479 | ) | (1) (2) (3) | 176,811 | 15,053 | 191,864 | |||||||||||
Goodwill |
125,315 | (635 | ) | (1) (3) | 124,680 | 7,898 | 132,578 | |||||||||||
Intangible assets, net |
107,960 | — | 107,960 | 5,776 | 113,736 | |||||||||||||
Deferred financing costs and other assets |
3,039 | 175 | (2) (4) | 3,214 | 1,153 | 4,367 | ||||||||||||
Total non-current assets |
414,604 | (1,939 | ) | 412,665 | 29,880 | 442,545 | ||||||||||||
Total assets |
$ | 458,642 | $ | (1,369 | ) | $ | 457,273 | $ | 104,851 | $ | 562,124 | |||||||
LIABILITIES AND PARTNERS' CAPITAL |
||||||||||||||||||
Current liabilities |
||||||||||||||||||
Accounts payable |
$ | 9,338 | $ | (499 | ) | (1) (2) (3) | $ | 8,839 | $ | 48,060 | $ | 56,899 | ||||||
Accrued liabilities |
9,778 | 645 | (1) (2) (4) | 10,423 | 5,653 | 16,076 | ||||||||||||
Capital leases and short-term debt |
3,932 | — | 3,932 | — | 3,932 | |||||||||||||
Customer deposits and advances |
2,811 | (106 | ) | (4) | 2,705 | — | 2,705 | |||||||||||
Current portion of long term-debt |
2,973 | — | 2,973 | — | 2,973 | |||||||||||||
Total current liabilities |
28,832 | 40 | 28,872 | 53,713 | 82,585 | |||||||||||||
Long-term debt |
164,766 |
— |
164,766 |
— |
164,766 |
|||||||||||||
Other long-term liabilities |
470 | 150 | (4) | 620 | — | 620 | ||||||||||||
Total liabilities |
194,068 | 190 | 194,258 | 53,713 | 247,971 | |||||||||||||
Partners' capital |
||||||||||||||||||
Predecessor capital |
— | — | — | 51,138 | 51,138 | |||||||||||||
Preferred units |
21,271 | (305 | ) | 20,966 | — | 20,966 | ||||||||||||
General partner interest |
404 | — | 404 | — | 404 | |||||||||||||
Class A common units |
145,360 | (826 | ) | 144,534 | — | 144,534 | ||||||||||||
Class B common units |
14,531 | (284 | ) | 14,247 | — | 14,247 | ||||||||||||
Class C common units |
83,008 | (144 | ) | 82,864 | — | 82,864 | ||||||||||||
Total partners' capital |
264,574 | (1,559 | ) | 263,015 | 51,138 | 314,153 | ||||||||||||
Total liabilities and partners' capital |
$ | 458,642 | $ | (1,369 | ) | $ | 457,273 | $ | 104,851 | $ | 562,124 | |||||||
F-51
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
3. Restatement and Recast of 2012 financial statements (Continued)
| |
Consolidated Statement of Operations For the year ended December 31, 2012 |
|||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
As Previously Reported |
Restatement Adjustments |
Description of Adjustments |
As Restated |
Recast Adjustments |
As Restated and Recast |
Discontinued Operations | As Adjusted for Discontinued Operations |
||||||||||||||||
REVENUES: |
||||||||||||||||||||||||
Crude oil storage, gathering and transportation |
$ | 21,007 | $ | 224 | (4) | $ | 21,231 | $ | (21,231 | ) | $ | — | $ | — | $ | — | ||||||||
Refined products terminaling and storage |
2,707 | — | 2,707 | (2,707 | ) | — | — | — | ||||||||||||||||
NGL distribution and sales |
127,184 | (1,150 | ) | (1) | 126,034 | (126,034 | ) | — | — | — | ||||||||||||||
Crude oil sales |
— | — | — | 290,284 | 290,284 | (31 | ) | 290,253 | ||||||||||||||||
Gathering, transportation and storage fees |
— | — | — | 14,627 | 14,627 | (6,384 | ) | 8,243 | ||||||||||||||||
NGL and refined product sales |
— | — | — | 119,116 | 119,116 | — | 119,116 | |||||||||||||||||
Refined products terminals and storage fees |
— | — | — | 984 | 984 | — | 984 | |||||||||||||||||
Other revenues |
— | — | — | 13,300 | 13,300 | (4,315 | ) | 8,985 | ||||||||||||||||
|
150,898 | (926 | ) | 149,972 | 288,339 | 438,311 | (10,730 | ) | 427,581 | |||||||||||||||
COSTS AND EXPENSES: |
||||||||||||||||||||||||
Cost of sales, excluding depreciation and amortization: |
89,537 | (187 | ) | (1) (2) (3) (4) | 89,350 | 285,658 | 375,008 | (6,217 | ) | 368,791 | ||||||||||||||
Operating expenses |
25,635 | 2,675 | (2) (3) (4) | 28,310 | 1,752 | 30,062 | (1,422 | ) | 28,640 | |||||||||||||||
General and administrative |
22,503 | (1,908 | ) | (2) (3) (4) | 20,595 | 816 | 21,411 | (428 | ) | 20,983 | ||||||||||||||
Depreciation and amortization |
14,384 | (607 | ) | (3) | 13,777 | 1,349 | 15,126 | (1,270 | ) | 13,856 | ||||||||||||||
Loss on disposal of assets |
482 | 660 | (3) | 1,142 | — | 1,142 | — | 1,142 | ||||||||||||||||
Total costs and expenses |
152,541 | 633 | 153,174 | 289,575 | 442,749 | (9,337 | ) | 433,142 | ||||||||||||||||
OPERATING LOSS |
(1,643 | ) | (1,559 | ) | (3,202 | ) | (1,236 | ) | (4,438 | ) | (1,393 | ) | (5,831 | ) | ||||||||||
OTHER INCOME (EXPENSE): |
||||||||||||||||||||||||
Interest expense |
(3,393 | ) | — | (3,393 | ) | (153 | ) | (3,546 | ) | 141 | (3,405 | ) | ||||||||||||
Loss on extinguishment of debt |
(497 | ) | — | (497 | ) | — | (497 | ) | — | (497 | ) | |||||||||||||
Other income |
313 | — | 313 | 2 | 315 | (68 | ) | 247 | ||||||||||||||||
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
(5,220 | ) | (1,559 | ) | (6,779 | ) | (1,387 | ) | (8,166 | ) | (1,320 | ) | (9,486 | ) | ||||||||||
Income tax expense |
(222 | ) | — | (222 | ) | — | (222 | ) | — | (222 | ) | |||||||||||||
LOSS FROM CONTINUING OPERATIONS |
$ | (5,442 | ) | $ | (1,559 | ) | $ | (7,001 | ) | $ | (1,387 | ) | $ | (8,388 | ) | $ | (1,320 | ) | $ | (9,708 | ) | |||
INCOME FROM DISCONTINUED OPERATIONS |
— | — | — | — | — | 1,320 | 1,320 | |||||||||||||||||
NET LOSS |
$ | (5,442 | ) | $ | (1,559 | ) | $ | (7,001 | ) | $ | (1,387 | ) | $ | (8,388 | ) | $ | — | $ | (8,388 | ) | ||||
Net loss attributable to preferred unitholders |
$ | 1,043 | $ | 305 | $ | 1,348 | $ | — | $ | 1,348 | $ | — | $ | 1,348 | ||||||||||
Net loss attributable to predecessor capital |
— | — | — | 1,387 | 1,387 | — | 1,387 | |||||||||||||||||
General partner's interest |
— | — | — | — | — | — | — | |||||||||||||||||
Net loss attributable to common unitholders |
$ | (4,399 | ) | $ | (1,254 | ) | $ | (5,653 | ) | $ | — | $ | (5,653 | ) | $ | — | $ | (5,653 | ) | |||||
Basic and diluted loss per unit: |
||||||||||||||||||||||||
Basic and diluted loss per unit |
$ | (0.94 | ) | $ | (0.27 | ) | $ | (1.21 | ) | $ | — | $ | (1.21 | ) | $ | — | $ | (1.21 | ) | |||||
F-52
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
3. Restatement and Recast of 2012 financial statements (Continued)
The following table presents certain line items within the Partnership's consolidated statement of cash flows impacted by the restatement and recast adjustments discussed above for the year ended December 31, 2012:
| |
Consolidated Statement of Cash Flows For the year ended December 31, 2012 |
|||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
As Previously Reported |
Restatement Adjustments |
Description of Adjustments |
As Restated |
Recast Adjustments |
As Restated and Recast |
||||||||||||
Operating Activities |
||||||||||||||||||
Net loss |
$ | (5,442 | ) | $ | (1,559 | ) | (1) (2) (3) | $ | (7,001 | ) | $ | (1,387 | ) | $ | (8,388 | ) | ||
Non-cash adjustments |
18,069 | (51 | ) | (3) | 18,018 | 1,349 | 19,367 | |||||||||||
Changes in working capital |
(6,687 | ) | 333 | (1) (2) (3) | (6,354 | ) | (11,615 | ) | (17,969 | ) | ||||||||
Net cash provided by (used in) operating activities |
5,940 | (1,277 | ) | 4,663 | (11,653 | ) | (6,990 | ) | ||||||||||
Investing Activities |
||||||||||||||||||
Capital expenditures |
(14,170 | ) | 567 | (3) | (13,603 | ) | (7,429 | ) | (21,032 | ) | ||||||||
Proceeds received from sale of assets |
216 | 710 | (3) | 926 | — | 926 | ||||||||||||
Financing Activities |
||||||||||||||||||
Contributions from the Predecessor |
— | — | — | 24,787 | 24,787 | |||||||||||||
4. Discontinued Operations
On June 30, 2014, the Partnership ("Seller") entered into and simultaneously closed an Asset Purchase Agreement (the "Purchase Agreement") with Gold Spur Trucking, LLC ("Buyer"), pursuant to which the Seller sold all the trucking and related assets and activities in North Dakota, Montana and Wyoming (the "Bakken Business") to the Buyer for a purchase price of $9,100,000. As a result, the Partnership recognized a loss on this sale of approximately $7,288,000 during the second quarter of 2014, which primarily relates to the write-off of a customer contract associated with the Bakken Business. In addition, immediately prior to the sale, the Partnership allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that was retained by the Partnership. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.
The Bakken Business operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The Partnership combined the cash flows from the Bakken Business with the cash flows from continuing operations for all periods presented in the consolidated statements of cash flows. The Bakken Business will not generate any continuing cash flows subsequent to the date of disposition. Prior to the classification as discontinued operations, the Partnership had reported the Bakken Business in its crude oil supply and logistics segment. The following table
F-53
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
4. Discontinued Operations (Continued)
summarizes selected financial information related to the Bakken Business's operations in the years ended December 31, 2011, 2012 and 2013.
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
Revenue from discontinued operations |
$ | — | $ | 10,730 | $ | 19,283 | ||||
Net income (loss) of discontinued operations, net of taxes |
— | 1,320 | (1,182 | ) | ||||||
5. Net Loss Per Unit
Loss per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships ("MLPs") when incentive distribution rights ("IDRs") and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. For the years ended December 31, 2011, 2012 and 2013, diluted loss from continuing operations per unit was equal to basic loss from continuing operations per unit because all instruments were antidilutive.
The preferred units earn cumulative distributions each quarter equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common units and (b) the minimum quarterly distribution of $0.50 per unit. The net loss attributable to preferred units includes cumulative distributions declared and the preferred units' proportionate share of net loss for the years ended December 31, 2011, 2012 and 2013. On August 1, 2013, all then-outstanding preferred units were converted to common units on a one-for-one basis (see Note 14).
6. Acquisitions
2011 Acquisitions
Acquisition of Conway Oil Company. On June 29, 2011, the Partnership, through its Pinnacle Propane subsidiary, acquired 100% of the operating assets of Conway Oil Company ("Conway Oil") for $9,540,000 in cash that was funded by partner contributions. Conway Oil is headquartered in Albuquerque, New Mexico and is in the retail and wholesale propane, gasoline and diesel fuel distribution business. Conway Oil has operations in Clovis, Tucumcari, Fort Sumner and Santa Rosa, New Mexico. Conway Oil distributes propane, gasoline and diesel to its customers throughout Eastern New Mexico and West Texas. This acquisition further strengthened the Partnership's presence throughout New Mexico, and added to its existing footprint in Southeast New Mexico and West Texas.
F-54
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Accounts receivable |
$ | 1,662 | ||
Inventory |
526 | |||
Other |
1 | |||
Total current assets |
2,189 | |||
Real estate |
||||
Property, plant and equipment |
6,147 | |||
Intangible assets: |
||||
Customer relationships |
494 | |||
Noncompete agreements |
468 | |||
Other intangible assets |
74 | |||
Total assets acquired |
9,372 | |||
Total liabilities assumed |
(137 | ) | ||
Total identifiable net assets acquired |
9,235 | |||
Goodwill |
305 | |||
Net assets acquired |
$ | 9,540 | ||
Goodwill associated with the Conway Oil acquisition principally results from synergies expected from combined operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820, "Fair Value Measurements," refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 15 years and noncompete agreements are amortized over a weighted average useful life of 5 years.
The operations of Conway Oil have been fully integrated into the Partnership's operations and no separate financial records were maintained. Therefore, it is impracticable to report the amounts of revenues and earnings of Conway Oil included in the consolidated results of operations related to the post acquisition periods.
Acquisition of Vista Propane (Midland 66). On September 19, 2011, the Partnership, through its Pinnacle Propane subsidiary, acquired 100% of the retail and wholesale distribution assets of Vista Propane, LLC ("Midland 66") for $9,389,000 in cash that was funded by partner contributions. The acquisition of Midland 66 added refined fuels, oils and lubricants to the Partnership's propane distribution products in West Texas and further complimented the Partnership's recent acquisition of Conway Oil in Eastern New Mexico.
F-55
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Cash |
$ | 696 | ||
Accounts receivable |
2,809 | |||
Inventory |
672 | |||
Other current assets |
4 | |||
Total current assets |
4,181 | |||
Property, plant and equipment |
3,870 | |||
Intangible assets: |
||||
Tradename |
440 | |||
Customer relationships |
605 | |||
Noncompete agreements |
217 | |||
Total assets acquired |
9,313 | |||
Total liabilities assumed |
(691 | ) | ||
Total identifiable net assets acquired |
8,622 | |||
Goodwill |
767 | |||
Net assets acquired |
$ | 9,389 | ||
Goodwill associated with the Midland 66 acquisition principally results from synergies expected from combined operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The tradename is amortized over a useful life of 30 years, customer relationships are amortized over a weighted average useful life of 15 years, and non-compete agreements are amortized over a weighted average useful life of 3 years.
The operations of Midland 66 have been fully integrated into the Partnership's operations and no separate financial records were maintained. Therefore, it is impracticable to report the amounts of revenues and earnings of Midland 66 included in the consolidated results of operations related to the post acquisition periods.
Acquisition of HBH. On November 15, 2011, the Partnership acquired substantially all of the community propane systems of HBH Operations, LLC and its affiliates ("HBH") for $2,388,000 in cash that was funded by borrowings under the Partnership's revolving acquisition credit facility, and a liability in the form of a promissory note that was fair valued at $1,664,000 ("HBH Note"). Total payments under the HBH Note are contingent based on the actual meter connections measured on the HBH Note's expiration date of December 31, 2016, with a minimum amount of $2,012,500. No payments in excess of the minimum amount are expected to occur. The fair value measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The acquisition of HBH further expanded the Partnership's coverage in community propane distribution systems in Texas.
F-56
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Accounts receivable |
$ | 47 | ||
Inventory |
72 | |||
Total current assets |
119 | |||
Property, plant and equipment |
2,115 | |||
Intangible assets: |
||||
Customer contracts |
902 | |||
Other |
48 | |||
Total assets acquired |
3,184 | |||
Total liabilities assumed |
(31 | ) | ||
Total identifiable net assets acquired |
3,153 | |||
Goodwill |
899 | |||
Net assets acquired |
$ | 4,052 | ||
Goodwill associated with the HBH acquisition principally results from synergies expected from combined operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer contracts are amortized over a weighted average useful life of 25 years.
The operations of HBH have been fully integrated into the Partnership's operations and no separate financial records were maintained. Therefore, it is impracticable to report the amounts of revenues and earnings of HBH included in the consolidated results of operations related to the post acquisition periods.
Other 2011 Acquisitions. In addition to the acquisitions disclosed above, during 2011, the Partnership acquired substantially all of the retail and wholesale propane distribution assets from companies summarized below:
Date of acquisition
|
Name of acquired entity | Total purchase price | ||||
|---|---|---|---|---|---|---|
| June 28, 2011 | Georgetown Propane, LLC | $ | 1,700 | |||
| July 5, 2011 | A+ Propane, Inc. | 342 | ||||
| September 7, 2011 | House Co-op Association | 776 | ||||
| December 12, 2011 | Arthur Propane, Inc. | 2,107 | ||||
The Partnership used borrowings under the Partnership's revolving acquisition credit facility to fund these acquisitions. These acquisitions further expanded the Partnership's existing propane distribution systems.
F-57
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the aggregated purchase price to the assets acquired and liabilities assumed related to the four acquisitions described above, which are individually insignificant:
Accounts receivable |
$ | 59 | ||
Inventory |
152 | |||
Total current assets |
211 | |||
Property, plant and equipment |
2,389 | |||
Intangible assets: |
||||
Customer relationships |
1,146 | |||
Noncompete agreements |
423 | |||
Total assets acquired |
4,169 | |||
Total liabilities assumed |
(104 | ) | ||
Total identifiable net assets acquired |
4,065 | |||
Goodwill |
860 | |||
Net assets acquired |
$ | 4,925 | ||
Goodwill associated with these acquisitions principally results from synergies expected from combined operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 11 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.
The operations of the above businesses have been fully integrated into the Partnership's operations and no separate financial records were maintained. Therefore, it is impracticable to report the amounts of revenues and earnings of these businesses included in the consolidated results of operations related to the post acquisition periods.
2012 Acquisitions
Acquisition of Heritage Propane Express, LLC. On June 7, 2012, the Partnership completed the acquisition of 100% of the outstanding membership interests in Heritage Propane Express, LLC ("HPX"). HPX is engaged in the business of preparing, distributing, marketing and selling 20-pound portable propane cylinders pre-filled with propane and collecting used 20-pound portable cylinders for refilling or disposal.
The acquisition of HPX added new channels of propane distribution to the Partnership's existing propane distribution system and provided a natural hedge to mitigate the seasonality associated with demand for propane. Consideration consisted of a payment of $61,727,000 in cash, which was funded by a combination of borrowings under the Partnership's revolving credit facility and capital contributions, and a note payable to the former owners of $6,612,000, which was repaid in 2012.
F-58
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Cash |
$ | 7,202 | ||
Accounts receivable |
7,306 | |||
Inventory |
2,427 | |||
Prepaid assets |
31 | |||
Total current assets |
16,966 | |||
Property, plant and equipment |
33,791 | |||
Intangible assets: |
||||
Trade name |
472 | |||
Customer relationships |
12,018 | |||
Noncompete agreements |
684 | |||
Other long term assets |
5 | |||
Total assets acquired |
63,936 | |||
Total liabilities assumed |
(8,399 | ) | ||
Total identifiable net assets acquired |
55,537 | |||
Goodwill |
12,802 | |||
Net assets acquired |
$ | 68,339 | ||
Liabilities assumed include $3,097,000 of accounts payable, $4,252,000 of accrued expenses, $435,000 of other long term liabilities, and $615,000 of long-term debt.
Goodwill associated with the HPX acquisition principally results from future growth potential into new geographical markets, as well as obtaining new large-volume or national customers. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names are amortized over an estimated useful life of one year, customer relationships are amortized over a weighted average useful life of 15 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.
Revenues attributable to HPX included in the consolidated statements of operations totaled $31,784,000 and $58,251,000 respectively, for the period from June 7, 2012 to December 31, 2012 and for the year ended December 31, 2013. The operations of HPX are not accounted for on a stand-alone basis by the Partnership, therefore, it is impracticable to report the amounts of earnings of HPX included in the consolidated results of operations related to the post acquisition periods.
Acquisition of Falco Energy Transportation. On July 20, 2012, the Partnership acquired all of the membership interests of Falco Energy Transportation, LLC and its subsidiaries ("Falco"). FET is engaged in providing crude oil gathering and transportation services to producers, marketers and refiners of crude oil.
The acquisition added new services to the Partnership's existing fee-based midstream operation. The total purchase price of $55,464,000 consisted of a payment of $41,561,000 in cash that was funded
F-59
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
by borrowings under the Partnership's revolving credit facility, and the issuance of 666,667 Class C Common Units representing limited partner interests in the Partnership valued at $13,903,000. The fair value of the units was determined using a discounted cash flow model that includes a market multiple applied to the terminal year (Level 3). The assumed liabilities include an assumed debt obligation of $6,532,000.
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Cash |
$ | 223 | ||
Accounts receivable |
4,850 | |||
Other receivable |
86 | |||
Prepaid assets |
925 | |||
Total current assets |
6,084 | |||
Property, plant and equipment |
15,737 | |||
Intangible assets: |
||||
Trademarks |
1,421 | |||
Customer relationships |
663 | |||
Noncompete agreements |
634 | |||
Customer contract |
11,285 | |||
Other |
61 | |||
Total assets acquired |
35,885 | |||
Total liabilities assumed |
(10,657 | ) | ||
Total identifiable net assets acquired |
25,228 | |||
Goodwill |
30,236 | |||
Net assets acquired |
$ | 55,464 | ||
Goodwill associated with the Falco acquisition principally results from the integration with the Partnership's other crude oil business. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trademarks are amortized over an estimated useful life of 10 years, customer relationships are amortized over a weighted average useful life of 7 years, non-compete agreements are amortized over a weighted average useful life of 5 years, and the customer contract is amortized over a useful life of 7 years.
Revenues attributable to Falco included in the consolidated statements of operations totaled $13,788,000 and $21,242,000, respectively, for the period from July 20, 2012 to December 31, 2012 and for the year ended December 31, 2013. The operations of Falco are not accounted for on a stand-alone basis by the Partnership, therefore, it is impracticable to report the amounts of earnings of Falco included in the consolidated results of operations related to the post acquisition periods.
F-60
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
Acquisition of the Parnon Gathering Assets. On August 3, 2012, JP Development acquired the Parnon Gathering Assets for $28,120,000 in cash. The Parnon Gathering Assets primarily provide crude oil supply and logistics for companies engaged in production, distribution, and marketing of crude oil. On February 12, 2014, the Partnership acquired the Parnon Gathering Assets from JP Development as part of the Dropdown Assets as described in Note 1.
The acquisition further expanded the Partnership's fee-based business in crude oil services operation.
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed on August 3, 2012:
Cash |
$ | 382 | ||
Accounts receivable |
30,322 | |||
Inventory |
7,886 | |||
Prepaid assets |
431 | |||
Total current assets |
39,021 | |||
Property, plant and equipment |
8,072 | |||
Intangible assets: |
||||
Trade name |
835 | |||
Customer relationships |
5,769 | |||
Other long term assets |
848 | |||
Total assets acquired |
54,545 | |||
Total liabilities assumed |
(34,323 | ) | ||
Total identifiable net assets acquired |
20,222 | |||
Goodwill |
7,898 | |||
Net assets acquired |
$ | 28,120 | ||
Goodwill associated with the acquisition of the Parnon Gathering Assets principally results from the integration with the Partnership's other crude oil business. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names are amortized over an estimated useful life of 1 year and customer relationships are amortized over a weighted average useful life of 5 years.
Revenues attributable to the Parnon Gathering Assets included in the consolidated statements of operations totaled $289,560,000 and $1,870,997,000, respectively, for the period from August 3, 2012 to December 31, 2012 and for the year ended December 31, 2013.
Acquisition of Parnon Storage, LLC. On August 3, 2012, the Partnership acquired 100% of the issued and outstanding membership interests in Parnon Storage, LLC for $91,936,000 in cash which was funded by a combination of borrowings under the Partnership's revolving credit facility and capital contributions. Parnon Storage, LLC is engaged in providing crude oil storage in Cushing, Oklahoma.
The acquisition further expanded the Partnership's fee-based business in crude oil services operation.
F-61
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Cash |
$ | 91 | ||
Prepaid assets |
347 | |||
Total current assets |
438 | |||
Property, plant and equipment |
52,958 | |||
Intangible assets: |
||||
Customer contract |
26,993 |
|||
Other intangible assets |
310 | |||
Favorable lease |
198 | |||
Total assets acquired |
80,897 | |||
Total liabilities assumed |
(2 | ) | ||
Total identifiable net assets acquired |
80,895 | |||
Goodwill |
11,041 | |||
Net assets acquired |
$ | 91,936 | ||
A portion of the acquired lease portfolio contained a favorable lease. The acquired lease terms were compared to current market lease terms to determine if the acquired lease was below or above the current rates tenants would pay for similar leases. The favorable lease is amortized to rent expense on a straight line basis over the life of the related lease, which is 45 years.
Goodwill associated with the Parnon Storage acquisition principally results from future growth potential which can be attributable to Parnon Storage's strategic location in Cushing, Oklahoma. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The customer contract is being amortized over a weighted average useful life of 7 years.
Revenues attributable to Parnon Storage included in the consolidated statements of operations totaled $6,224,000 and $14,524,000, respectively, for the period from August 3, 2012 to December 31, 2012 and for the year ended December 31, 2013. The operations of Parnon Storage are not accounted for on a stand-alone basis by the Partnership, therefore, it is impracticable to report the amounts of earnings of Parnon Storage included in the consolidated results of operations related to the post acquisition periods.
Acquisition of North Little Rock, Arkansas and Caddo Mills, Texas Terminals. On November 27, 2012, the Partnership acquired substantially all of the assets of Truman Arnold Companies' refined petroleum products pipeline terminal in Caddo Mills, Texas ("Caddo") and in North Little Rock, Arkansas ("ATT"), for $62,500,000 in cash and 2,500,000 Class C Common Units representing limited partner interests in the Partnership valued at $69,875,000. ATT and Caddo are engaged in the terminal, storage and distribution of refined products.
The acquisitions added new services to the Partnership's existing fee-based midstream operation.
F-62
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed:
Other receivable |
$ | 83 | ||
Property, plant and equipment |
25,488 | |||
Intangible assets: |
||||
Customer relationships |
45,457 | |||
Noncompete agreements |
227 | |||
Other |
40 | |||
Total assets acquired |
71,295 | |||
Total liabilities assumed |
(83 | ) | ||
Total identifiable net assets acquired |
71,212 | |||
Goodwill |
61,163 | |||
Net assets acquired |
$ | 132,375 | ||
Goodwill associated with the ATT and Caddo acquisitions principally results from synergies expected from expanded operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 15 years and non-compete agreements are amortized over a weighted average useful life of 3 years.
Revenues attributable to ATT and Caddo included in the consolidated statements of operations totaled $2,706,000 and $24,011,000 for the period from November 27, 2012 to December 31, 2012 and for the year ended December 31, 2013. The operations of ATT and Caddo are not accounted for on a stand-alone basis by the Partnership, therefore, it is impracticable to report the amounts of earnings of ATT and Caddo included in the consolidated results of operations related to the post acquisition periods.
Other 2012 Acquisitions. In addition to the above acquisitions, the Partnership acquired the entities summarized below, for a total purchase price of $23,823,000, of which $23,225,000 was paid in cash and $598,000 was issued as a promissory note to the seller:
Date of acquisition
|
Name of acquired entity | Total purchase price | ||||
|---|---|---|---|---|---|---|
January 10, 2012 |
MK Gas Ltd. (d/b/a Bill Smith Butane) | $ | 1,833 | |||
May 1, 2012 |
Reynolds Brothers Propane, Inc. | 4,515 | ||||
December 31, 2012 |
Tri-State Propane, Inc. | 2,818 | ||||
December 31, 2012 |
SemStream Arizona Propane, L.L.C. | 14,657 | ||||
F-63
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The following table represents the allocation of the aggregated purchase price to the assets acquired and liabilities assumed related to the three acquisitions described above, which are individually insignificant:
Cash |
$ | 202 | ||
Accounts receivable |
3,080 | |||
Inventory |
1,346 | |||
Prepaid assets |
894 | |||
Total current assets |
5,522 | |||
Property, plant and equipment |
16,107 | |||
Intangible assets: |
||||
Customer relationships |
1,512 | |||
Noncompete agreements |
151 | |||
Other |
411 | |||
Total assets acquired |
23,703 | |||
Total liabilities assumed |
(2,605 | ) | ||
Total identifiable net assets acquired |
21,098 | |||
Goodwill |
2,725 | |||
Net assets acquired |
$ | 23,823 | ||
Goodwill associated with these acquisitions principally results from synergies expected from combined operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 13 years.
The goodwill amounts noted for all 2012 acquisitions reflect the difference between purchase prices less the fair value of net assets acquired. Goodwill was warranted because these acquisitions enhance the Partnership's current operations, and certain acquisitions are expected to reduce costs through synergies with existing operations. The Partnership does not believe that the acquired intangible assets have any significant residual value at the end of their respective useful life.
The operations of the above businesses are fully integrated into the Partnership's operations and no separate financial results were maintained. Therefore, it is impracticable for the Partnership to report the amounts of revenues and earnings of the above acquirees included in the consolidated results of operations.
2013 Acquisitions
The following acquisitions by JP Development were acquired by the Partnership in the Common Control Acquisition.
Acquisition of Wildcat Permian Services LLC. On October 7, 2013, JP Development acquired all of the issued and outstanding equity interests of Wildcat Permian for a total consideration of $212,804,000 in cash. Wildcat Permian owns and operates a long-term contracted oil pipeline system in Crockett and
F-64
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
Reagan Counties, Texas. On February 12, 2014, the Partnership acquired Wildcat Permian from JP Development as part of the Dropdown Assets as described in Note 1.
The acquisition extended the Partnership's reach into the rapidly growing southern Midland Basin, which further diversified the Partnership's portfolio of transportation and storage assets.
The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed on October 7, 2013:
Cash |
$ | 2,570 | ||
Accounts receivable |
16,068 | |||
Inventory |
283 | |||
Short-term prepaid asset |
134 | |||
Total current assets |
19,055 | |||
Property, plant and equipment |
33,962 | |||
Long-term prepaid asset |
951 | |||
Intangible assets: |
||||
Customer relationships |
67,700 | |||
Total assets acquired |
121,668 | |||
Total liabilities assumed |
(17,227 | ) | ||
Total identifiable net assets acquired |
104,441 | |||
Goodwill |
108,363 | |||
Net assets acquired |
$ | 212,804 | ||
Goodwill associated with the Wildcat Permian acquisition principally results from expected future growth potential as well as the synergies expected from integrations with the Partnership's other crude oil business. The Partnership allocated $11,242,000 of the goodwill associated with the Wildcat Permian acquisition to its crude oil supply and logistics business. The fair value of the acquired intangible asset was estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 17 years.
Revenues attributable to Wildcat Permian and included in the consolidated statement of operations totaled $10,878,000 for the period from October 7, 2013 to December 31, 2013.
Other 2013 Acquisitions. In addition to the acquisition described above, in 2013, JP Development also acquired following businesses for a total purchase price of $27,048,000. The total consideration consisted of $23,085,000 paid in cash, JP Development's investment in the Partnership's Class C Common Units representing limited partner interests valued at $1,628,000, a contingent earn-out with a fair value of $1,280,000 that is subject to the achievement of certain trucking revenue goals at Alexander Oil Field Service, Inc. ("AOFS"), and a contingent earn-out with a fair value of $1,055,000 that is subject to the achievement of certain trucking revenue goals at Highway Pipeline, Inc. ("HPI"). The AOFS earn-out period covers the period from September 1, 2013 to August 31, 2015, and the maximum earn-out which could be earned is $1,628,000 over the course of two years. The HPI earn-out period covers the period from January 1, 2014 to December 31, 2016, and the maximum earn-out that could be earned is $3,000,000 over the course of three years.
F-65
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
The fair value measure of the contingent earn-outs was estimated by applying an expected present value technique based on the probability-weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The contingent earn-outs were established at the time of the acquisitions and are revalued at each reporting period. The Partnership reduced the fair value of the AOFS contingent earn-out liability to $750,000 as of December 31, 2013 based on the actual post-acquisition performance results of the business, as well as the Partnership's revised expectation of the possible future outcome. The fair value of the HPI contingent earn-out liability increased to $1,067,000 as of December 31, 2013 as a result of the accretion of the liability. The liabilities are recorded in other-long term liabilities on the consolidated balance sheets.
Date of acquisition
|
Name of acquired entity | Total purchase price | ||||
|---|---|---|---|---|---|---|
July 15, 2013 |
BMH Propane, LLC (d/b/a Valley Gas) | $ | 2,437 | |||
August 30, 2013 |
Alexander Oil Field Service, Inc. | 7,792 | ||||
October 11, 2013 |
Highway Pipeline, Inc. | 16,819 | ||||
On February 12, 2014, the Partnership acquired the above businesses from JP Development in the Common Control Acquisition described in Note 1.
The following table represents the allocation of the aggregated purchase price to the assets acquired related to the three acquisitions described above, which are individually insignificant at their respective original acquisition dates by JP Development:
Accounts receivable |
$ | 504 | ||
Inventory |
15 | |||
Total current assets |
519 | |||
Property, plant and equipment |
8,503 | |||
Intangible assets: |
||||
Trade names and trademarks |
286 | |||
Customer relationships |
8,022 | |||
Noncompete agreements |
429 | |||
Total assets acquired |
17,759 | |||
Total liabilities assumed |
(475 | ) | ||
Total identifiable net assets acquired |
17,284 | |||
Goodwill |
9,764 | |||
Net assets acquired |
$ | 27,048 | ||
Goodwill associated with these acquisitions principally results from synergies expected from integrated operations and from assembled workforce. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names and trademarks are amortized over an estimated useful life of 2 years, customer relationships are amortized over a weighted average useful life of 6 years, and non-compete agreements are amortized over an estimated useful life of 3 years.
F-66
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
6. Acquisitions (Continued)
Revenues attributable to the three acquisitions above and included in the consolidated statement of operations totaled $5,781,000, for the period from each respective acquisition date to December 31, 2013.
The goodwill amounts noted for all 2013 acquisitions reflect the difference between purchase prices less the fair value of net assets acquired. Goodwill was warranted because these acquisitions enhance the Partnership's current operations, and certain acquisitions are expected to reduce costs through synergies with existing operations. The Partnership does not believe that the acquired intangible assets have any significant residual value at the end of their respective useful life.
Pro Forma Information
The following unaudited pro forma information summarizes the results of operations for the years ended December 31, 2012 and 2013 as if the significant acquisition of JP Permian (effectively acquired by JPE on October 7, 2013—see Note 1—Organization and Description of the Business) had been completed at the beginning of the prior comparative year. Financial information of certain acquisitions was impractical to obtain and accordingly have not been included in the pro forma financial information presented below. For the Parnon Gathering Assets acquisition, net income for the years preceding the acquisition were unavailable, and as a result are not included in the pro forma information below. The Parnon Gathering assets generated $218,668,000 of operating revenues and $217,218,000 of direct operating expenses for the period from January 1, 2012 to August 2, 2012.
The pro forma data combines the Partnership's consolidated results with those of the acquired entities (prior to acquisition) for the periods shown. The results are adjusted for amortization, depreciation, interest expense and income taxes relating to the acquisitions. No effect has been given to cost reductions or operating synergies in this presentation. These pro forma amounts do not purport to be indicative of the results that would have actually been achieved if the acquisitions had occurred as of the beginning of the periods presented or that may be achieved in the future. The pro forma amounts are as follows:
| |
Year ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
| |
2012 | 2013 | |||||
| |
(unaudited) |
(unaudited) |
|||||
Pro forma consolidated revenue |
$ | 504,222 | $ | 2,105,201 | |||
Pro forma consolidated net loss |
$ | (565 | ) | $ | (17,344 | ) | |
F-67
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
7. Inventory
Inventory consists of the following as of December 31, 2012 and 2013:
| |
December 31, | ||||||
|---|---|---|---|---|---|---|---|
| |
2012 | 2013 | |||||
| |
(Restated and Recast) |
|
|||||
Crude Oil |
$ | 14,155 | $ | 31,099 | |||
NGLs |
2,654 | 5,274 | |||||
Diesel |
349 | 438 | |||||
Materials, supplies and equipment |
2,477 | 1,768 | |||||
Total inventory |
$ | 19,635 | $ | 38,579 | |||
8. Property, Plant and Equipment, net
Property, plant and equipment, net consists of the following as of December 31, 2012 and 2013:
| |
December 31, 2012 | December 31, 2013 | |||||
|---|---|---|---|---|---|---|---|
| |
(Restated and Recast) |
|
|||||
Land |
$ | 7,229 | $ | 7,922 | |||
Buildings and improvements |
9,847 | 11,354 | |||||
Transportation equipment |
35,424 | 54,448 | |||||
Storage and propane tanks |
122,897 | 132,309 | |||||
Pipeline and linefill |
4,951 | 22,421 | |||||
Office furniture and fixture |
2,119 | 6,035 | |||||
Other equipment |
10,315 | 24,222 | |||||
Construction-in-progress |
9,751 | 10,899 | |||||
Total property, plant and equipment |
202,533 | 269,610 | |||||
Less: accumulated depreciation |
(10,669 | ) | (31,517 | ) | |||
Property, plant and equipment, net |
$ | 191,864 | $ | 238,093 | |||
Depreciation expense totaled $1,831,000, $8,796,000 and $21,127,000 for 2011, 2012 and 2013, respectively, which is included in depreciation and amortization expense in the consolidated statements of operations.
F-68
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
9. Goodwill and Intangible Assets
Intangible assets consist of the following for the years ended December 31, 2012 and 2013:
| |
December 31, 2012 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Gross carrying amount |
Accumulated amortization |
Net carrying amount |
|||||||
Customer relationships |
$ | 74,875 | $ | (3,406 | ) | $ | 71,469 | |||
Noncompete agreements |
3,299 | (582 | ) | 2,717 | ||||||
Trade names |
3,372 | (789 | ) | 2,583 | ||||||
Customer contract |
39,179 | (2,455 | ) | 36,724 | ||||||
Favorable lease |
198 | (2 | ) | 196 | ||||||
Other |
62 | (15 | ) | 47 | ||||||
Total |
$ | 120,985 | $ | (7,249 | ) | $ | 113,736 | |||
| |
December 31, 2013 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
Gross carrying amount |
Accumulated amortization |
Net carrying amount |
|||||||
Customer relationships |
$ | 82,898 | $ | (9,907 | ) | $ | 72,991 | |||
Noncompete agreements |
3,728 | (1,392 | ) | 2,336 | ||||||
Trade names |
2,146 | (283 | ) | 1,863 | ||||||
Customer contract |
106,879 | (9,205 | ) | 97,674 | ||||||
Favorable lease |
198 | (6 | ) | 192 | ||||||
Other |
111 | (66 | ) | 45 | ||||||
Total |
$ | 195,960 | $ | (20,859 | ) | $ | 175,101 | |||
Amortization expense totaled $1,010,000, $6,330,000 and $15,068,000 for December 31, 2011, 2012 and 2013, respectively, which is included in depreciation and amortization expense in the consolidated statements of operations.
The Partnership amortizes the intangible assets over their estimated benefit period on a straight-line basis.
The estimated future amortization expense for amortizable intangible assets to be recognized is as follows:
2014 |
$ | 19,110 | ||
2015 |
18,947 | |||
2016 |
18,556 | |||
2017 |
17,704 | |||
2018 |
16,761 | |||
Thereafter |
84,023 | |||
Total |
$ | 175,101 | ||
F-69
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
9. Goodwill and Intangible Assets (Continued)
Goodwill activity in 2012 and 2013 consists of the following:
| |
Crude oil pipelines and storage |
Crude oil supply and logistics |
Refined products terminals and storage |
NGL distribution and sales |
Total | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
|
|
|
(Restated and Recast) |
|
|||||||||||
Balance at January 1, 2012 |
$ | — | $ | — | $ | — | $ | 6,713 | $ | 6,713 | ||||||
Goodwill acquired during the year |
11,041 | 38,134 | 61,163 | 15,527 | 125,865 | |||||||||||
Balance at December 31, 2012 |
11,041 | 38,134 | 61,163 | 22,240 | 132,578 | |||||||||||
Goodwill acquired during the year |
97,121 | 11,911 | — | 9,095 | 118,127 | |||||||||||
Balance at December 31, 2013 |
$ | 108,162 | $ | 50,045 | $ | 61,163 | $ | 31,335 | $ | 250,705 | ||||||
10. Accrued Liabilities
Accrued liabilities are comprised of the following as of December 31, 2012 and 2013:
| |
December 31, | ||||||
|---|---|---|---|---|---|---|---|
| |
2012 | 2013 | |||||
| |
(Restated and Recast) |
|
|||||
Taxes payable |
$ | 1,884 | $ | 3,406 | |||
Accrued payroll and employee benefits |
3,654 | 8,138 | |||||
Accrued professional fees |
695 | 3,093 | |||||
Royalties payable |
2,671 | 3,910 | |||||
Short-term derivative liabilities |
1,013 | 200 | |||||
Other |
6,159 | 4,001 | |||||
|
$ | 16,076 | $ | 22,748 | |||
11. Capital Leases and Other Short Term Debt
Capital Leases. The Partnership has certain leases for buildings, transportation equipment and office equipment, which are accounted for as capital leases. The leases mature between 2013 and 2021.
F-70
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
11. Capital Leases and Other Short Term Debt (Continued)
Assets under capital lease are recorded within property, plant and equipment, net. The following is a summary of assets held under such agreements.
| |
December 31, | ||||||
|---|---|---|---|---|---|---|---|
| |
2012 | 2013 | |||||
Buildings and improvements |
$ | 138 | $ | 138 | |||
Transportation equipment |
877 | 406 | |||||
Office equipment |
104 | 108 | |||||
|
1,119 | 652 | |||||
Less: Accumulated depreciation |
(687 | ) | (369 | ) | |||
Assets under capital lease, net |
$ | 432 | $ | 283 | |||
Scheduled principal repayments of capital lease obligations are as follows:
Years ending December 31, |
||||
2014 |
$ | 178 | ||
2015 |
148 | |||
2016 |
94 | |||
2017 |
64 | |||
2018 |
20 | |||
Thereafter |
51 | |||
|
555 | |||
Less: amounts representing interest |
(251 | ) | ||
Total obligations under capital leases |
304 | |||
Less: current portion |
(103 | ) | ||
Long-term capital lease obligation |
$ | 201 | ||
The long term capital lease obligation is included within other long-term liabilities in the consolidated balance sheets.
Other Short Term Debt. The Partnership finances a portion of its annual insurance premiums which it pays in installments over eleven months. As of December 31, 2012 and 2013, the respective outstanding balances under this arrangement were $3,756,000 at an interest rate of 3.4% and $49,000 at an interest rate of 3.2%. The outstanding amount was repaid in the first quarter of 2014 and the Partnership is no longer financing insurance premiums. In addition, the Partnership had a $386,000 bank overdraft outstanding as of December 31, 2013.
F-71
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
12. Long-Term Debt
Long-term debt consists of the following at December 31, 2012 and 2013:
| |
December 31, | ||||||
|---|---|---|---|---|---|---|---|
| |
2012 | 2013 | |||||
WFB acquisition revolver |
$ | 149,407 | $ | 169,407 | |||
WFB working capital revolver |
8,000 | 8,150 | |||||
F&M loans |
7,647 | 4,135 | |||||
HBH note payable |
1,626 | 1,470 | |||||
JPED note payable |
— | 1,000 | |||||
Reynolds note payable |
618 | 344 | |||||
Noncompete notes payable |
441 | 340 | |||||
Total long-term debt |
$ | 167,739 | $ | 184,846 | |||
Less: Current maturities |
(2,973 | ) | (698 | ) | |||
Total long-term debt, net of current maturities |
$ | 164,766 | $ | 184,148 | |||
Wells Fargo Credit Agreement. On December 23, 2011, the Partnership entered into a credit agreement with Wells Fargo Bank, N.A. (the "WFB Credit Agreement") for working capital requirements, for the acquisition of propane entities and to pay off existing debt. The WFB Credit Agreement consisted of a $20,000,000 working capital revolving loan (the "WFB Working Capital Revolver") and a $30,000,000 acquisition revolving loan (the "WFB Acquisition Revolver") (collectively, the "WFB Commitments"), which were scheduled to mature on December 23, 2015. The WFB Commitments required for quarterly interest payments commencing on March 31, 2012 and any outstanding borrowings due upon maturity. The Partnership's obligations under the WFB Commitments were collateralized by all of the Partnership's assets and certain letters of credit, as required.
On June 5, 2012, the Partnership amended the WFB Credit Agreement, which increased the WFB Acquisition Revolver by $10,000,000 to a commitment of $40,000,000. On September 6, 2012, the Partnership amended the WFB Agreement, which increased the WFB Acquisition Revolver by an additional $140,000,000 to a total commitment of $180,000,000.
At December 31, 2012 and 2013, the unused balance of the WFB Working Capital Revolver and the WFB Acquisition Revolver was $11,800,000 and $30,593,000, and $10,850,000 and $10,593,000, respectively. Issued and outstanding letters of credit, which reduced available borrowings under the WFB Credit Agreement, totaled $200,000 and $1,000,000 at December 31, 2012 and 2013, respectively. Quarterly, the Partnership paid a variable commitment fee on the unused commitment based on a margin determined by the Partnership's leverage ratio, as defined by the WFB Credit Agreement. The Partnership paid a commitment fee of 0.5% of the unused balance of the WFB Working Capital Revolver and the WFB Acquisition Revolver during 2012 and 2013.
The WFB Credit Agreement contained various restrictive covenants and compliance requirements including:
- •
- Maintenance of certain financial covenants commencing March 31, 2012 including a leverage ratio, interest coverage ratio, current ratio, and distribution coverage ratio.
F-72
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
12. Long-Term Debt (Continued)
- •
- Financial statement reporting requirements, including monthly and quarterly unaudited financial statement reporting and
annual audited financial statement reporting.
- •
- Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and
coverage ratios are maintained before and after the cash distribution.
- •
- Upon certain events, such as bankruptcy filing or involuntary liquidation and as defined in the WFB Credit Agreement, all outstanding debt obligations would have become immediately payable and all commitments and further obligations to issue any additional letters of credit would have been immediately terminated.
At the time of each borrowing under the WFB Commitments, the Partnership may elect either the LIBOR borrowing rate or the alternative base rate as defined in the WFB Credit Agreement. The applicable elected borrowing rates are re-determined based on the calculated leverage ratio as of the end of each fiscal quarter. The effective borrowing rate for the WFB Commitments was 3.5% and 3.9% for the years ended December 31, 2012 and 2013, respectively. To hedge the interest rate risk associated with the WFB commitments, the Partnership entered into an interest rate swap to hedge $75,000,000 of the outstanding debt balance (see Note 13).
The Partnership was not in compliance with certain covenants during 2012 and the first quarter of 2013, including annual reporting requirements for the fiscal year ended December 31, 2012, paying distributions and making certain acquisitions without satisfying certain leverage covenants. In April 2013, the Partnership obtained waivers for the covenants which were out of compliance. On June 5, 2013 the Partnership received a waiver to further extend the annual reporting requirements for the fiscal year ended December 31, 2012. The Partnership was not in compliance with the leverage ratio covenant during the third quarter of 2013, which noncompliance was waived pursuant to a waiver received by the Partnership on December 6, 2013. As noted below, the WFB Credit Agreement was repaid on February 12, 2014.
On February 12, 2014, the Partnership entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement.
Bank of America Credit Agreement. On February 12, 2014, the Partnership entered into a credit agreement with Bank of America, N.A. (the "BOA Credit Agreement) for working capital requirements, for the acquisition of entities, and to pay off its existing WFB Commitments and F&M Loans. The BOA Credit Agreement consists of a $275,000,000 revolving loan. The BOA Credit Agreement will mature on February 12, 2019. The Partnership's obligations under the BOA Credit Agreement are collateralized by substantially all of the Partnership's assets.
Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable margin. The initial applicable margin is (a) 2.00% for prime rate borrowings and 3.00% for LIBOR borrowings. The applicable margin is subject to an adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.
F-73
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
12. Long-Term Debt (Continued)
The Partnership is required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.
The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:
- •
- Maintenance of certain financial covenants including a leverage ratio, interest coverage ratio, and a current ratio.
- •
- Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited
financial statement reporting.
- •
- Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.
The Partnership was in compliance with all covenants under the BOA Credit Agreement since the inception of the agreement.
F&M Bank & Trust Company Credit Agreement. On July 20, 2012, the Partnership entered into an amended and restated credit agreement with F&M Bank & Trust Company for the purchase of new, and the refinancing of existing, vehicles and equipment. The F&M Bank Credit Agreement consists of several term loans (collectively, "F&M Loans"). The Partnership's obligations under the F&M Loans were collateralized by the Partnership's vehicles and equipment financed by these loans.
The F&M Loans have a credit commitment of $9,000,000 and an outstanding loan balance of $4,135,000 as of December 31, 2013, with maturity dates ranging from February 7, 2015 through September 7, 2017. The F&M Loans call for monthly principal payments, plus accrued interest thereon.
At the time of each payment, the F&M Loans call for payment of accrued interest on the outstanding principal balance at the Prime Rate plus 0.5%, subject to an interest rate floor of 5.0%. The interest rate is reset at each payment date.
The outstanding balance of $4,135,000 on the F&M Loans was paid off in full on February 12, 2014, with the proceeds from the BOA Credit Agreement.
HBH Note Payable. The Partnership issued a $2,012,500 non-interest bearing promissory note in conjunction with the acquisition of HBH on November 15, 2011. The carrying value of this note is $1,626,000 and $1,470,000 as of December 31, 2012 and December 31, 2013, respectively, which is based on an interest rate of 5.0%. This balance is payable every January and July through December 31, 2016 based on the number of meter connections above a threshold. The minimum amount due is $2,012,500. The final remaining balance on this loan is due in full on December 31, 2016. Accretion expense, included as a component of interest expense, totaled $15,000, $82,000 and $69,000 for the 2011, 2012 and 2013, respectively. The fair value measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs.
F-74
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
12. Long-Term Debt (Continued)
Reynolds Note Payable. The Partnership issued a $645,000 non-interest bearing promissory note as partial consideration for the acquisition of Reynolds Brother Propane on May 1, 2012. The note is payable in two installments of $295,000 and $350,000 at the first and second anniversary of the acquisition closing date (i.e. May 1, 2013 and May 1, 2014), respectively. The carrying value of the note is $618,000 and $344,000 at December 31, 2012 and December 31, 2013, respectively, which is based on an effective imputed interest rate of 4.5%. Accretion expense, included as a component of interest expense totaled $20,000 and $21,000, respectively for 2012 and 2013.
Non-Compete Notes Payable. As part of the acquisition of HPX in June 2012, the Partnership acquired several promissory notes, which were issued prior to acquisition by HPX as consideration for several non-compete agreements unrelated to the acquisition transaction. Each of the agreements has a five year term and is non-interest bearing. The fair value of the agreements is $441,000 and $340,000 at December 31, 2012 and December 31, 2013, which is based on an effective imputed interest rate of 3.5%.
Related Party Note Payable. On November 5, 2013, The Partnership issued a $1,000,000 promissory note to JP Development for working capital requirements. The note will mature on November 5, 2016 and currently bears interest at 4.75%. The interest rate is subject to an adjustment each quarter equal to the weighted average rate of JP Development's outstanding indebtedness during the most recently ended fiscal quarter. Accrued interest on the note is payable quarterly in arrears. On March 20, 2014, the Partnership repaid the promissory note in full.
Scheduled principal repayments of long-term debt for each of the next five years ending December 31 and thereafter are as follows:
2014 |
$ | 698 | ||
2015 |
344 | |||
2016 |
1,386 | |||
2017 |
726 | |||
2018 |
— | |||
Thereafter |
181,692 | |||
Total |
$ | 184,846 | ||
13. Derivative Instruments
The Partnership is exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, the Partnership has established comprehensive risk management policies and procedures. The Board of Directors is responsible for the overall management of these risks, including monitoring exposure limits. The Partnership does not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. That is, the Partnership does not speculate using derivative instruments.
Commodity Price Risk. The Partnership's NGL distribution and sales segment is exposed to market risks related to the volatility of propane prices. Management believes it is prudent to limit the variability of a portion of the Partnership's propane purchases. To meet this objective, the Partnership
F-75
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
13. Derivative Instruments (Continued)
uses a combination of financial instruments including, but not limited to, forward physical contracts and financial swaps to manage its exposure to market fluctuations in propane prices. There were no commodity derivatives as of and for the year ended December 31, 2011. The following table details the outstanding commodity-related derivatives as of December 31, 2012 and 2013, none of which were designated as hedges for accounting purposes.
| |
December 31, 2013 | December 31, 2012 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Notional Volume | Maturity | Notional Volume | Maturity | |||||||||
Derivatives not designated as hedging contracts: |
|||||||||||||
Propane (Gallons) : |
|||||||||||||
Forward Contracts |
— | — | 1,954,800 | Jan 2013 - Nov 2013 | |||||||||
Swaps |
1,728,778 | Jan 2014 - Mar 2014 | 6,513,764 | Jan 2013 - Dec 2013 | |||||||||
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of variable-rate borrowings under its revolving credit facilities. Management believes it is prudent to limit the variability of a portion of the Partnership's interest payments. To meet this objective, the Partnership entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of its debt with a variable-rate component. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, the Partnership receives variable interest rate payments and makes fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that is swapped. There were no derivative instruments related to the Partnership's debt obligations during fiscal year 2011. The following table summarizes the interest rate swaps outstanding as of December 31, 2012 and 2013, none of which were designated as hedges for accounting purposes.
| |
|
Notional Amount Outstanding | |||||||
|---|---|---|---|---|---|---|---|---|---|
Term
|
Type(1) | December 31, 2013 | December 31, 2012 | ||||||
July 2015 |
Pay a fixed rate of 0.50% and receive a floating rate | $ | 32,000,000 | $ | 32,000,000 | ||||
September 2015 |
Pay a fixed rate of 0.47% and receive a floating rate | $ | 43,000,000 | $ | 43,000,000 | ||||
- (1)
- Floating rates are based on 1-month LIBOR
Credit Risk. By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Partnership exposes itself to counterparty credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative contract is negative, the Partnership owes the counterparty and, therefore, it does not possess credit risk. The Partnership minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties. The Partnership has entered into Master International Swap Dealers Association ("ISDA") Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.
Fair Value of Derivative Instruments. The Partnership measures derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the
F-76
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
13. Derivative Instruments (Continued)
derivative contracts to a present value. These valuations utilize primarily observable ("level 2") inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of the Partnership's derivative contracts are designated as hedging instruments. The following table summarizes the fair values of the Partnership's derivative contracts included in the consolidated balance sheets as of December 31, 2012 and 2013 (in thousands).
| |
|
Asset Derivatives | Liability Derivatives | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Balance Sheet Location | December 31, 2013 |
December 31, 2012 |
December 31, 2013 |
December 31, 2012 |
||||||||||
Derivatives not designated as hedging contracts: |
|||||||||||||||
Commodity Forward Contracts |
Accrued Liabilities | $ | — | $ | — | $ | — | $ | (833 | ) | |||||
Commodity Swap Contracts |
Prepaid expenses and other current assets | 498 | 221 | — | — | ||||||||||
Interest Rate Swap Contracts |
Accrued Liabilities | — | — | (200 | ) | (180 | ) | ||||||||
Interest Rate Swap Contracts |
Other Long-term liabilities | — | — | (4 | ) | (76 | ) | ||||||||
As of December 31, 2012 and 2013, the Partnership presented the fair value of the derivative contracts on a gross basis on the consolidated balance sheets. In the statement of cash flows, the effects of settlements of derivative instruments are classified in operating activities, consistent with the related transactions.
The following tables summarize the amounts recognized with respect to the Partnership's derivative instruments within the consolidated statements of operations.
| |
|
Amount of Gain/(Loss) Recognized in Income on Derivatives |
|||||||
|---|---|---|---|---|---|---|---|---|---|
| |
Location of Gain/(Loss) Recognized in Income on Derivatives |
December 31, 2013 | December 31, 2012 | ||||||
Derivatives not designated as hedging contracts: |
|||||||||
Commodity derivatives |
Cost of sales | $ | 902 | $ | 640 | ||||
Interest rate swaps |
Interest expense | (168 | ) | (257 | ) | ||||
14. Partners' Capital
Issuances in Connection with Formation. On May 5, 2010, JP Energy GP LLC, a Delaware limited liability company, as the initial general partner of the Partnership (the "Predecessor GP"), and JP Energy Holdings, LLC, a Texas limited liability company, executed the Agreement of Limited Partnership (the "Original Partnership Agreement") as the initial general partner and sole limited partner, respectively. Pursuant to an Assignment Agreement dated May 6, 2010 by and between the Predecessor GP and CB Capital Holdings II, LLC, a Texas limited liability company ("CB Capital"), all of the IDRs of the Partnership were transferred from the Predecessor GP to CB Capital.
On May 10, 2010, the Original Partnership Agreement was superseded by the Amended and Restated Agreement of Limited Partnership of the Partnership (the "First Amended Partnership
F-77
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
14. Partners' Capital (Continued)
Agreement"), which was entered into by the Predecessor GP as general partner and by several private investors as limited partners. In connection with the Partnership's formation and entry into the Original Partnership Agreement and the First Amended Partnership Agreement, the Partnership issued 45 general partner units (the "general partner interest") to the Predecessor GP and 474,375 common units to 31 private investors. Additionally, the Partnership subsequently issued 439,600 common units in connection with capital calls and acquisitions on several occasions between October 2010 and June 2011. In all instances, common units were issued at a price of $20.00 per common unit, other than issuances to private investors on June 27, 2011, which were issued at $22.00 per common unit.
Second Amended and Restated Agreement of Limited Partnership. On June 27, 2011, in connection with the Partnership's recapitalization by Lonestar Midstream Holdings, LLC ("Lonestar"), an affiliate of ArcLight, the Partnership executed the Second Amended and Restated Agreement of Limited Partnership (the "Existing Partnership Agreement"). The Existing Partnership Agreement established and authorized the issuance of Class A Common Units and Class B Common Units. Pursuant to the Existing Partnership Agreement, all 913,975 of the then-outstanding common units and 26,503 unallocated common units that were issued under the First Amended Partnership Agreement were converted on a one-for-one basis into Class B Common Units. In addition, pursuant to a Contribution Agreement entered into as of June 27, 2011 by and among the Predecessor GP, CB Capital and JP Energy GP II LLC, a Delaware limited liability company and the successor general partner of the Partnership (the "General Partner"), (i) the general partner interest was transferred from the Predecessor GP to the General Partner and (ii) CB Capital transferred all of the IDRs in the Partnership to the General Partner.
ArcLight Capital Commitment. Pursuant to a Purchase Agreement dated June 27, 2011 (the "Purchase Agreement") by and among the Partnership, the General Partner and Lonestar, the board of directors of Lonestar committed to provide up to $100,000,000 to fund acquisitions or for other valid partnership purposes. Additionally, the Purchase Agreement provided that, (i) in return for the first $25,000,000 of capital committed, the Partnership would issue, subject to board of directors approval, Lonestar Preferred Units (as defined in the Existing Partnership Agreement) at a price of $22.00 per Preferred Unit and (ii) in return for the remaining $75,000,000 of capital committed, the Partnership would issue, subject to board of directors approval, Lonestar Class A Common Units at a price of $22.00 per Class A Common Unit. On July 12, 2012, the Partnership, the General Partner, the Predecessor GP, CB Capital and Lonestar entered into an Amended and Restated Purchase Agreement (the "Amended and Restated Purchase Agreement") that increased Lonestar's capital commitment in the aggregate to the Partnership and to JP Energy Development LP to $300,000,000. On October 4, 2013, the parties to the Amended and Restated Purchase Agreement terminated the Amended and Restated Purchase Agreement and any obligations thereunder.
Preferred Units. On June 27, 2011, September 8, 2011 and December 9, 2011, the Partnership authorized and issued to Lonestar 524,746 Series A Convertible Preferred Units, 552,348 Series B Convertible Preferred Units, and 59,270 Series C Convertible Preferred Units, respectively. In each case, the issuances were made at a price of $22.00 per unit and were authorized in connection with an amendment to the Existing Partnership Agreement. The proceeds were primarily used to fund the Partnership's various acquisitions in 2011.
F-78
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
14. Partners' Capital (Continued)
Except as set forth below, the Series A Convertible Preferred Units, Series B Convertible Preferred Units, and Series C Convertible Preferred Units (collectively, the "Preferred Units") have the same rights and preferences, and are subject to the same duties and obligations as the Class A Common Units. The Preferred Units earn cumulative distributions each quarter equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the Preferred Units had been converted into common units and (b) the minimum quarterly distribution of $0.50 per unit. Such cumulative distributions are to be accrued and paid prior to any other distributions to other unitholders of the Partnership. Holders of the Preferred Units have the right to convert the Preferred Units to Class A Common Units at a ratio equal to the quotient of (i) $22.00 per unit plus all accrued and accumulated but unpaid distributions thereon per unit, divided by (ii) $22.00 per unit. Commencing on the date on which the minimum quarterly distribution is paid with respect to the fourth full quarter following the respective issuance date of each series of Preferred Units, the Partnership has the right, at its own option, to convert all or part of the corresponding Preferred Units into a number of Class A Common Units as determined in the manner described above. No such conversion occurred during 2011 or 2012. In the event of any liquidation of the Partnership, including a change of control event, the Preferred Units will be treated as having been converted into Class A Common Units.
On August 1, 2013, the Partnership executed the Series A, Series B, and Series C Forced Conversion Notice ("Conversion Notice") with Lonestar. Pursuant to the Conversion Notice, all 524,746 of the then-outstanding Series A Convertible Preferred Units, all 552,348 of the then-outstanding Series B Convertible Preferred Units, and all 59,270 of the then-outstanding Series C Convertible Preferred Units held by Lonestar were converted on a one-for-one basis into Class A Common Units.
Common Units. In December 2011, the Partnership issued 49,821 Class A Common Units to Lonestar for total net proceeds of $1,096,000 to partially fund its acquisition of substantially all of the assets of Arthur Propane Inc.
On several occasions in 2012, pursuant to various amendments to the Existing Partnership Agreement, the Partnership issued an aggregate of 6,818,183 Class A Common Units to Lonestar, for total net proceeds of $150,063,000 to partially fund various acquisitions.
On July 20, 2012, in connection with the acquisition of FET, the Partnership issued 666,667 Class C Common Units to FET's former members as consideration for the acquisition valued at $13,903,000. On November 27, 2012, in connection with the acquisitions of ATT and Caddo, the Partnership issued 2,500,000 Class C Common Units valued at $69,875,000.
On July 18, 2013, the Partnership issued 45,860 Class C Common Units to JP Development for total net proceeds of $1,628,000. On August 13, 2013, the Partnership issued 42,254 Class C Common Units to JP Development for total net proceeds of $1,500,000.
With the exception of the distribution of proceeds upon a "Change of Control Event" as described in the Partnership Agreement, all Class A Common Units, Class B Common Units, and Class C Common Units (collectively, the "Existing Common Units") have the same terms and conditions. Upon the occurrence of the Initial Public Offering, except as described in "Subordinated Units" below, all
F-79
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
14. Partners' Capital (Continued)
Class A Common Units, Class B Common Units, Class C Common Units and Preferred Units will automatically convert into Existing Common Units on a one-for-one basis.
Subordinated Units. The Existing Partnership Agreement provides that, in connection with the Initial Public Offering, the General Partner may, in its sole and absolute discretion and upon written notice to the limited partners, convert all or a portion of the Common Units into Subordinated Units on a one-for-one basis without the necessity of any vote or approval of any other partner.
Available Cash. Cash available for distribution for any quarter generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the General Partner to: (i) provide for the proper conduct of the Partnership's business; (ii) comply with applicable law, any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Partnership is a party or by which it is bound or its assets are subject; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters; provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the minimum quarterly distribution on all Common Units, plus any cumulative common unit arrearage on all Common Units, with respect to such quarter; and, provided further, that disbursements made by the Partnership or its subsidiaries or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of available cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within such Quarter if the General Partner so determines.
General Partner Interest and IDRs. The General Partner is entitled to its pro rata share of the Partnership's quarterly distributions in accordance with its percentage interest. As of both December 31, 2012 and 2013, the General Partner had 45 general partner units. The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest.
The IDRs held by the General Partner entitle it to receive an increasing share of available cash when pre-defined distribution targets are achieved. The General Partner's IDRs are not reduced if the Partnership issues additional units in the future and the General Partner does not contribute a proportionate amount of capital to the Partnership to maintain its general partner interest.
Distributions of Available Cash from Operating Surplus. The Existing Partnership Agreement requires that the Partnership make distributions of available cash from operating surplus for any quarter prior to or after the subordination period in the following manner:
- •
- first, to all preferred unitholders, pro rata, until each unitholder receives an amount per unit equal to the greater of
(a) the amount of aggregate distributions in cash for such quarter that would be payable with respect to a preferred unit if such preferred unit had converted at the beginning of such quarter
into common units and (b) the minimum quarterly distribution (currently set at $0.50 per common unit) per unit outstanding for such quarter;
- •
- second, to all unitholders holding common units and to the General Partner, pro rata, until there has been distributed in respect of each common unit then outstanding an amount equal to the minimum quarterly distribution for such quarter;
F-80
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
14. Partners' Capital (Continued)
- •
- third, to all unitholders holding common units and to the General Partner, pro rata, until there has been distributed in
respect of each common unit then outstanding an amount equal to the excess of the first target distribution (currently set at $0.625 per common unit) less the minimum quarterly distribution for such
quarter;
- •
- fourth, (i) to the General Partner in accordance with its percentage interest, (ii) 13% to holders of the
IDRs, pro rata, and (iii) to all unitholders holding common units a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs, until there has been
distributed in respect of each common unit then outstanding an amount equal to the excess of the second target distribution (currently set at $0.75 per common unit) less the first target distribution
for such quarter;
- •
- fifth, (i) to the General Partner in accordance with its percentage interest, (ii) 23% to holders of the
IDRs, pro rata, and (iii) to all unitholders holding common units a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs, until there has been
distributed in respect of each common unit then outstanding an amount equal to the excess of the third target distribution (currently set at $1.00 per common unit) less the second target distribution
for such quarter; and
- •
- thereafter, (i) to the General Partner in accordance with its percentage interest, (ii) 48% to holders of the IDRs, pro rata, and (iii) to all unitholders a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs.
Distributions. The Existing Partnership Agreement requires the distribution of all of the Partnership's available cash within sixty (60) days after the end of each quarter to unitholders of record on the applicable record date, as determined by the General Partner. During the years ended December 31, 2011, 2012 and 2013, the Partnership paid quarterly distributions as follows:
Distribution Date
|
Cash Distribution (per unit) | |||
|---|---|---|---|---|
February 2011 |
$ | 0.50 | ||
May 2011 |
0.50 | |||
February 2012 |
0.50 | |||
May 2012 |
0.50 | |||
August 2012 |
0.50 | |||
November 2012 |
0.50 | |||
February 2013 |
0.50 | |||
July 2013 |
0.50 | |||
August 2013 |
0.50 | |||
The Partnership's ability to distribute available cash each quarter is restricted by the provisions of the Existing Partnership Agreement, which make all distributions subject to the requirements of Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware LP Act").
In addition, the Partnership's ability to distribute available cash each quarter is restricted under its credit agreements, by and among the Partnership, the subsidiaries of the Partnership party thereto, the administrative agent, and the lenders time to time party thereto, which contains certain restrictions on
F-81
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
14. Partners' Capital (Continued)
distributions, including the absence of any events of default as defined in the credit agreements, a maximum leverage threshold, the maintenance of a minimum distribution coverage ratio and cash balance and a maximum amount to be distributed based on certain calculations described in greater detail in the credit agreements.
Valuation of Units. Fair value of the Class B and Class C common units is estimated based on enterprise value calculated using the discounted cash flow method (Level 3). Material unobservable inputs used to estimate the fair value include weighted average cost of capital ("WACC") and market multiple used in calculating the terminal value. The following table presents the inputs used on each major valuation date during 2012 and 2013:
| |
February 29, 2012 | July 20, 2012 | November 27, 2012 | April 19, 2013 | December 31, 2013 | |||||
|---|---|---|---|---|---|---|---|---|---|---|
WACC |
13.61% - 14.11% | 10.96% - 11.46% | 8.95% - 9.45% | 9.41% - 9.91% | 10.71% - 11.21% | |||||
Market multiple |
9.25 - 9.75 times | 8.75 - 9.25 times | 10.5 - 11 times | 10.5 - 11 times | 12.05 - 12.55 times |
15. Unit-Based Compensation
Restricted (Non-vested) Class B Common Units of JPE. From time to time, the Partnership grants service condition restricted class B common units to certain key employees. Such service condition restricted common units require the recipients' continuous employment with the Partnership and vest, according to the vesting schedule in each respective grant agreement, over certain periods, typically three to five years.
In addition to the service condition grants described above, pursuant to the employment agreements, as amended, between the Partnership and certain employees, the Partnership is obligated to grant restricted class B common units to those employees upon their achievement of certain agreed-upon performance goals that are measured by different milestones. Different milestone achievements will cause different amounts of restricted class B common units to be awarded. The maximum amount of the restricted class B common units to be issued pursuant to these employment agreements, as amended, is 100,000 units. During the year ended December 31, 2012, 75,000 restricted class B common units were issued as a result of the employee's achievement of certain milestones. These restricted units will vest on the earlier of (1) the expiration of the applicable lock-up period for the employee following the occurrence of an initial public offering of the Partnership; and (2) termination of the employment agreement for cause, disability, death, for good reason, or for other reasons, as defined in the employment agreements.
Fair value of the restricted class B common units equaled the fair value of the Partnership's common unit at the respective grant dates. The Partnership estimates the fair value of its common unit by dividing the estimated total enterprise value by the number of outstanding units. Estimated total enterprise value was determined using the income approach of discounting the estimated future cash flow to its present value. The Partnership also estimated a 10% forfeiture rate in calculating the unit-based compensation expense.
There were no restricted class B common unit grants in 2011. During the years ended December 31, 2012 and 2013, equity-based compensation expense of $2,010,000 and $948,000, respectively, was recorded in general and administrative expense in the consolidated statement of operations related to class B common units.
F-82
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
15. Unit-Based Compensation (Continued)
The following table summarizes the restricted (non-vested) class B common units during the years ended December 31, 2012 and 2013:
| 2012 | |||||||
|---|---|---|---|---|---|---|---|
Restricted (Non-Vested) Common Units
|
Units | Weighted Average Grant Date Fair Value |
|||||
Outstanding at the beginning of the period |
— | $ | — | ||||
Granted—service condition |
82,500 | 20.99 | |||||
Granted—performance condition |
75,000 | (1) | 19.51 | ||||
Vested—service condition |
(14,500 | ) | 19.91 | ||||
Vested—performance condition |
— | — | |||||
Forfeited—service condition |
— | — | |||||
Forfeited—performance condition |
— | — | |||||
Outstanding at the end of period |
143,000 | 20.04 | |||||
- (1)
- At December 31, 2012, 25,000 performance condition class B common units were granted but not issued because the performance goal has not been met.
| 2013 | |||||||
|---|---|---|---|---|---|---|---|
Restricted (Non-Vested) Common Units
|
Units | Weighted Average Grant Date Fair Value |
|||||
Outstanding at the beginning of the period |
143,000 | $ | 20.04 | ||||
Granted—service condition |
68,500 | 34.91 | |||||
Granted—performance condition |
— | — | |||||
Vested—service condition |
(23,633 | ) | 23.37 | ||||
Vested—performance condition |
— | — | |||||
Forfeited—service condition |
(10,000 | ) | 19.51 | ||||
Forfeited—performance condition |
— | — | |||||
Outstanding at the end of period |
177,867 | 25.58 | |||||
The Partnership makes distributions to non-vested restricted class B common units on a 1:1 ratio with the per unit distributions paid to common units. Upon the vesting of the restricted class B common units, the Partnership intends to settle these obligations with common units. Accordingly, the Partnership expects to recognize an aggregate of $2,610,000 of compensation expense related to non-vested restricted class B common units over a weighted average period of 1.81 years.
During 2012, ArcLight transferred 3,000 of the Partnership's Class A common units to an employee of ArcLight who worked as a contractor for the Partnership. As a result, the Partnership recorded $63,000 of unit based compensation expenses as an increase to Partner's Capital.
Restricted (Non Vested) common units of CB Capital and Predecessor GP. During 2012, certain employees of the Partnership received restricted common unit grants from CB Capital and Predecessor GP as incentive compensation for their services to the Partnership. These restricted
F-83
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
15. Unit-Based Compensation (Continued)
common units are service condition only and the requisite service periods vary from immediately vesting upon grant to five years. Accordingly, the Partnership has recorded compensation expense for these grants in accordance with FASB ASC 505 50 "Equity Based Payments to Non Employees". The Partnership is not responsible for payment of these unit based compensation arrangements and all expense amounts are recorded in general and administrative expense with a corresponding increase to Partners' Capital.
The following table summarizes the restricted (non-vested) common units of CB Capital and Predecessor GP during the years ended December 31, 2012 and 2013:
| 2012 | |||||||
|---|---|---|---|---|---|---|---|
Restricted (Non-Vested) Common Units
|
CB Capital | Predecessor GP | |||||
Outstanding at the beginning of the period |
— | — | |||||
Granted |
1,302 | 1,360 | |||||
Vested |
(1,105 | ) | (1,118 | ) | |||
Forfeited |
— | — | |||||
Outstanding at the end of period |
197 | 242 | |||||
| 2013 | |||||||
|---|---|---|---|---|---|---|---|
Restricted (Non-Vested) Common Units
|
CB Capital | Predecessor GP | |||||
Outstanding at the beginning of the period |
197 | 242 | |||||
Granted |
— | — | |||||
Vested |
(76 | ) | (109 | ) | |||
Forfeited |
(103 | ) | (104 | ) | |||
Outstanding at the end of period |
18 | 29 | |||||
During the year ended December 31, 2012, the Partnership recorded unit based compensation expense of $412,000 in general and administrative expenses in the consolidated statements of operations.
16. Commitments and Contingencies
Legal Matters. The Partnership is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the partnership's consolidated financial position, results of operations, or liquidity.
Environmental Matters. The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
F-84
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
16. Commitments and Contingencies (Continued)
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Partnerships activities. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Partnership accounts for environmental contingencies in accordance with the ASC Topic 410 related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At both December 31, 2012 and 2013, the Partnership had no significant environmental matters.
Asset retirement obligations (ARO). The Partnership has contractual obligations to perform dismantlement and removal activities in the event that some assets, such as storage tanks, are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. The Partnership has determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have either been in existence for many years or are relatively new assets and with regular maintenance will continue to be in service for many years to come. In addition, it is not possible to predict when demand for the service will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, the Partnership cannot reasonably estimate the fair value of the associated ARO's and therefore, no ARO liability is recorded as of December 31, 2012 and 2013. Additionally, many of these assets could be re-deployed for a similar use. The Partnership will continue to monitor these assets and if sufficient information becomes available for us to reasonably determine the settlement dates, an ARO will be recorded for these assets in the relevant periods.
Operating Leases. The Partnership leases various buildings, land, storage facilities, transportation vehicles and office equipment under operating leases. Certain of the leases contain renewal and purchase options. The Partnership's aggregate rental expense for such leases was $543,000, $1,363,000 and $3,298,000 for the years ended December 31, 2011, 2012 and 2013, respectively, of which $84,000, $77,000 and $0 was paid to a related party through a sublease for the Partnership's (previously occupied) corporate offices, respectively, for each fiscal period ended. Additionally, the Partnership assumed a land lease in the acquisition of Parnon Storage, LLC on August 3, 2012. Equal payments of $10,000 are due each month over the remaining 44 year lease period with no implied interest rate noted in the lease agreement.
F-85
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
16. Commitments and Contingencies (Continued)
Minimum future payments under non-cancelable operating leases as of December 31, 2013 and thereafter are as follows:
2014 |
$ | 6,174 | ||
2015 |
5,973 | |||
2016 |
5,712 | |||
2017 |
2,957 | |||
2018 |
1,731 | |||
Thereafter |
5,497 | |||
|
$ | 28,044 | ||
17. Reportable Segments
During the first quarter of 2014, as a result of the Common Control Acquisition described in Note 1, the Partnership realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for the year ended December 31, 2012 to reflect this new segment adjustment. For the year ended December 31, 2011, the Partnership's operations consisted of only one reportable segment, NGL distribution and sales.
The Partnership's operations are located in the United States and are organized into four reportable segments: crude oil supply and logistics; crude oil pipelines and storage; refined products terminals and storage; and NGL distribution and sales.
Crude oil pipelines and storage. The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 40,000 barrels of storage capacity. The Partnership also operates a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.
Crude oil supply and logistics. The crude oil supply and logistics segment consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. The Partnership conducts crude oil supply activities by purchasing crude oil for its own account from producers, aggregators and traders and selling crude oil to traders and refiners. The Partnership also owns a fleet of crude oil gathering and transportation trucks operating in and around high-growth drilling areas such as the Mid-Continent, the Eagle Ford shale, and the Permian Basin. As described in Note 4, the disposition of the Bakken Business impacts the crude oil supply and logistics segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information tables. Accordingly, the Partnership has recast the segment information.
Refined products terminals and storage. The refined products terminals and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal has storage capacity of 550,000 barrels from 11 tanks and is primarily served by the refined products pipeline operated by
F-86
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
17. Reportable Segments (Continued)
Enterprise TE Products Pipeline Company LLC. The Caddo Mills terminal has storage capacity of 770,000 barrels from 10 tanks and is served by the Explorer Pipeline.
NGL distribution and sales. The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 48 states through a network of over 17,700 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in six states in the southwest region of the U.S., the Partnership sells NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. The Partnership also owns a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.
Corporate and other. Corporate and other includes general partnership expenses associated with managing all of the Partnership's reportable segments.
The Partnership accounts for intersegment revenues as if the revenues were to third parties.
The Partnership's chief operating decision maker ("CODM") evaluates the segments' operating performance based on Adjusted EBITDA. Adjusted EBITDA is defined by the Partnership as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring. During the first quarter of 2014, the Partnership's CODM began reviewing Adjusted EBITDA that excluded certain transaction costs that were not previously included. As a result, the Partnership has revised previously reported amounts to conform to the current year presentation.
The following tables reflect certain financial data for each reportable segment for the years ended December 31, 2011, 2012 and 2013.
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
|
(Restated and Recast) |
|
|||||||
External Revenues: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | 6,224 | $ | 25,401 | ||||
Crude oil supply and logistics |
— | 292,618 | 1,872,956 | |||||||
Refined products terminals and storage |
— | 2,706 | 24,011 | |||||||
NGLs distribution and sales |
67,156 | 126,033 | 179,865 | |||||||
Total revenues |
$ | 67,156 | $ | 427,581 | $ | 2,102,233 | ||||
F-87
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
17. Reportable Segments (Continued)
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
|
(Restated and Recast) |
|
|||||||
Intersegment Revenues: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | — | $ | — | ||||
Crude oil supply and logistics |
— | — | 5,573 | |||||||
Refined products terminals and storage |
— | — | — | |||||||
NGLs distribution and sales |
— | — | — | |||||||
Intersegment eliminations |
— | — | (5,573 | ) | ||||||
Total intersegment revenues |
$ | — | $ | — | $ | — | ||||
Cost of Sales, excluding depreciation and amortization: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | 224 | $ | 8,894 | ||||
Crude oil supply and logistics |
— | 289,275 | 1,852,249 | |||||||
Refined products terminals and storage |
— | 974 | 4,683 | |||||||
NGLs distribution and sales |
49,048 | 79,904 | 105,488 | |||||||
Intersegment eliminations |
— | — | (5,573 | ) | ||||||
Amounts not included in segment Adjusted EBITDA |
— | (1,586 | ) | (1,110 | ) | |||||
Total cost of sales, excluding depreciation and amortization |
$ | 49,048 | $ | 368,791 | $ | 1,964,631 | ||||
Operating Expenses: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | 1,072 | $ | 3,044 | ||||
Crude oil supply and logistics |
— | 2,464 | 8,501 | |||||||
Refined products terminals and storage |
— | 280 | 2,464 | |||||||
NGLs distribution and sales |
9,374 | 24,746 | 47,307 | |||||||
Amounts not included in segment Adjusted EBITDA |
210 | 78 | 609 | |||||||
Total operating expenses |
$ | 9,584 | $ | 28,640 | $ | 61,925 | ||||
Depreciation and Amortization: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | 2,217 | $ | 6,846 | ||||
Crude oil supply and logistics |
— | 2,267 | 5,847 | |||||||
Refined products terminals and storage |
— | 1,015 | 6,162 | |||||||
NGLs distribution and sales |
2,800 | 8,151 | 13,981 | |||||||
Corporate and other |
41 | 206 | 509 | |||||||
Total depreciation and amortization |
$ | 2,841 | $ | 13,856 | $ | 33,345 | ||||
F-88
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
17. Reportable Segments (Continued)
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
|
(Restated and Recast) |
|
|||||||
Adjusted EBITDA: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | 4,836 | $ | 13,353 | ||||
Crude oil supply and logistics |
— | (40 | ) | 14,686 | ||||||
Refined products terminals and storage |
— | 1,161 | 16,100 | |||||||
NGLs distribution and sales |
6,494 | 14,022 | 15,518 | |||||||
Total Adjusted EBITDA from reportable segments |
$ | 6,494 | $ | 19,979 | $ | 59,657 | ||||
Capital Expenditures: |
||||||||||
Crude oil pipelines and storage |
$ | — | $ | — | $ | 1,251 | ||||
Crude oil supply and logistics |
— | 13,123 | 3,159 | |||||||
Refined products terminals and storage |
— | — | 4,482 | |||||||
NGLs distribution and sales |
1,983 | 6,577 | 16,009 | |||||||
Corporate and other |
232 | 1,332 | 1,927 | |||||||
Total capital expenditures |
$ | 2,215 | $ | 21,032 | $ | 26,828 | ||||
A reconciliation of Adjusted EBITDA to net loss from continuing operations is included in the table below.
| |
Year ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | 2013 | |||||||
| |
|
(Restated and Recast) |
|
|||||||
Total Adjusted EBITDA from reportable segments |
$ | 6,494 | $ | 19,979 | $ | 59,657 | ||||
Other expenses not allocated to reportable segments |
(3,669 | ) | (8,174 | ) | (27,396 | ) | ||||
Depreciation and amortization |
(2,841 | ) | (13,856 | ) | (33,345 | ) | ||||
Interest expense |
(633 | ) | (3,405 | ) | (9,075 | ) | ||||
Loss on extinguishment of debt |
(95 | ) | (497 | ) | — | |||||
Income tax expense |
(35 | ) | (222 | ) | (208 | ) | ||||
Loss on disposal of assets |
(68 | ) | (1,142 | ) | (1,492 | ) | ||||
Unit-based compensation |
— | (2,485 | ) | (948 | ) | |||||
Total gain on commodity derivatives |
— | 640 | 902 | |||||||
Net cash payments for commodity derivatives settled during the period |
— | 946 | 209 | |||||||
Transaction costs and other non-cash items |
(354 | ) | (1,492 | ) | (1,343 | ) | ||||
Net loss from continuing operations |
$ | (1,201 | ) | $ | (9,708 | ) | $ | (13,039 | ) | |
F-89
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
17. Reportable Segments (Continued)
Total assets from the Partnership's reportable segments as of December 31 were as follows:
| |
December 31, 2012 |
December 31, 2013 |
|||||
|---|---|---|---|---|---|---|---|
| |
(Restated and Recast) |
|
|||||
Crude oil pipelines and storage |
$ | 89,862 | $ | 313,580 | |||
Crude oil supply and logistics |
174,312 | 208,420 | |||||
Refined products terminals and storage |
135,051 | 132,325 | |||||
NGLs distribution and sales |
153,418 | 178,450 | |||||
Corporate and other |
9,481 | 10,627 | |||||
Total assets |
$ | 562,124 | $ | 843,402 | |||
18. Related Parties
During 2011, 2012 and 2013, the Partnership entered into transactions with Enogex Holdings, an entity partially owned by ArcLight Capital. Enogex Holdings is a provider of rack sales, propane and trucks. For the years ended December 31, 2011, 2012 and 2013, the Partnership paid $469,000, $391,000 and $10,000, respectively for propane purchases from Enogex Holdings, which is included in cost of sales in the consolidated statements of operations. There were no amounts due to Enogex Holdings as of December 31, 2012 or 2013.
During 2011, 2012 and 2013, the Partnership entered into transactions with CAMS Bluewire, an entity in which ArcLight Capital holds a non-controlling interest. CAMS Bluewire provides IT support for the Partnership. For the years ended December 31, 2011, 2012 and 2013, the Partnership paid $51,000, $321,000 and $691,000, respectively for IT support and consulting services, and for purchases of IT equipment which are included in operating expenses, general and administrative expenses and property plant and equipment in the consolidated statements of operations and the consolidated balance sheets. The total amounts due to CAMS Bluewire as of December 31, 2012 and 2013 are $224,000 and $38,000, respectively.
As a result of the acquisition of ATT, Truman Arnold Companies ("TAC") owns certain Class C common units in the Partnership. In addition, Mr. Greg Arnold, President and CEO of TAC, is also a director of the Partnership. The Partnership's refined products terminals and storage segment sells refined products to TAC. As ATT was acquired in November 2012, there were no revenues from TAC to be reported for 2011. For the years ended December 31, 2012 and 2013, the Partnership's revenue from TAC was $1,744,000 and $14,473,000, respectively. As of December 31, 2012 and 2013, the Partnership had trade receivable balances due from TAC of $1,744,000 and $1,048,000, respectively, which are included in receivables from related parties on the consolidated balance sheets.
In 2013, the Partnership's NGL distribution and sales segment began purchasing refined products from TAC. In 2013, the Partnership paid $187,000 for refined product purchases from TAC, which is included in cost of sales in the consolidated statements of operations. The total amount due to TAC as of December 31, 2013 is $119,000.
F-90
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
18. Related Parties (Continued)
Beginning July 2013, the Partnership does not have any employees. The employees supporting the operations of the Partnership are employees of GP II, and as such, the Partnership funds GP II for payroll and other payroll-related expenses incurred by the Partnership. As of December 31, 2013, the Partnership had a receivable balance due from GP II of $1,611,000 as a result of the timing of payroll funding, which is included in receivables from related parties on the consolidated balance sheet.
The Partnership performs certain management services for JP Development. The Partnership receives a monthly fee of $50,000 for these services. The monthly fee reduced general and administrative expenses in the consolidated statement of operations by $50,000 and $600,000 for the years ended December 31, 2012 and 2013, respectively.
JP Development has a pipeline transportation business that provides crude oil pipeline transportation services to the Partnership's crude oil supply and logistics segment. As a result of utilizing JP Development's pipeline transportation services, during the years ended December 31, 2012 and 2013, the Partnership incurred pipeline tariff fees of $1,841,000 and $16,944,000, respectively, which have been included in costs of sales on the consolidated statements of operations. Such amounts were not settled in cash during the years ended December 31, 2012 and 2013, rather, they were treated as deemed contributions/distributions from/to JP Development, as discussed in Note 1.
As discussed in Note 12, on November 5, 2013, the Partnership issued a $1,000,000 promissory note to JP Development for working capital requirements. The note will mature on November 5, 2016 and currently bears interest at 4.75%. The interest rate is subject to an adjustment each quarter equal to the weighted average rate of JP Development's outstanding indebtedness during the most recently ended fiscal quarter. Accrued interest on the note is payable quarterly in arrears. As of December 31, 2013, $7,000 of interest payable on the promissory note is included in payables to related parties on the consolidated balance sheet. On March 20, 2014, the Partnership repaid this promissory note in full.
As discussed in Note 14, on July 18, 2013, the Partnership issued 45,860 Class C Common Units to JP Development for total net proceeds of $1,628,000 and on August 13, 2013, the Partnership issued 42,254 Class C Common Units to JP Development for total net proceeds of $1,500,000.
As discussed in Note 16, for the years ended December 31, 2011 and 2012, the Partnership paid $84,000 and $77,000, respectively, to a related party through a sublease for the Partnership's previously occupied corporate offices.
19. Subsequent Event
Series D Preferred Units. On March 28, 2014 (the "Issue Date"), the Partnership authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the "Series D Preferred Units") for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the "Subscription Agreement") by and among the Partnership, GP II and Lonestar. This transaction resulted in proceeds to the Partnership of $40,000,000.
The Series D Preferred Units are a new class of voting equity security that ranks senior to all of the Partnership's other classes or series of equity securities with respect to distribution rights and rights upon liquidation. The Series D Preferred Units have voting rights identical to the voting rights of the Partnership's Class A Common Units and will vote with the Partnership's common units as a single
F-91
JP ENERGY PARTNERS LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Tabular dollar amounts, except unit and per unit data, are in thousands)
19. Subsequent Event (Continued)
class, such that each Series D Preferred Unit (including each Series D Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series D Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.
Each Series D Preferred Unit (including Series D Paid-in-kind ("PIK") Units issued as in-kind distributions) earns a cumulative distribution that is payable in either cash or Series D PIK Units as described below. The distribution rate for any such unit is (A) with respect to any distribution for the four consecutive quarters commencing with the quarter ended June 30, 2014, an amount equal to the greater of (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.66, and (B) with respect to any distribution for any quarterly period after the quarter ending March 31, 2015, (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.825. If the Partnership does not have sufficient available cash to make cash distributions with respect to the common units, the Partnership may pay all or any portion of the Series D Distribution in-kind during each quarter commencing on the Issue Date and ending on March 31, 2015.
The Series D Preferred Units (including Series D PIK Units issued as in-kind distributions) are convertible into common units of the Partnership on a one-for-one basis by Lonestar at any time after December 31, 2014. The Partnership may redeem the Series D Preferred Units (A) at any time prior to the Partnership's initial public offering of its common units or (B) during the period commencing on the Issue Date and ending on April 1, 2015, whichever is later, in each case at a price of $22.00 per Series D Preferred Unit, subject to adjustment pursuant to the provisions of the Partnership Agreement.
F-92
To
the Board of Directors
JP Energy Partners LP
FBO Caddo Mills Pipeline Terminal of
Truman Arnold Companies &
Arkansas Terminaling and Trading, Inc.
We have audited the accompanying combined financial statements of Caddo Mills Pipeline Terminal of Truman Arnold Companies & Arkansas Terminaling and Trading, Inc. (collectively, the Company), which comprise the combined balance sheets as of November 27, 2012 and December 31, 2011, and the related combined statements of income, stockholders' equity and parent company's investment and cash flows for the period from January 1, 2012 through November 27, 2012 and the year ended December 31, 2011, and the related notes to the combined financial statements.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Caddo Mills Pipeline Terminal of Truman Arnold Companies & Arkansas Terminaling and Trading, Inc. as of November 27, 2012 and December 31, 2011, and results of its operations and its cash flows for the period from January 1, 2012 through November 27, 2012 and the year ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
/s/
Travis Wolff, LLP
Dallas, Texas
May 20, 2013
F-93
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Combined Balance Sheets
November 27, 2012 and December 31, 2011
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
ASSETS |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ | 1,464,677 | $ | 797,450 | |||
Accounts receivable—trade |
1,153,500 | 1,100,919 | |||||
Related party receivable |
332,492 | 377,387 | |||||
Inventory |
353,724 | 177,094 | |||||
Prepaid expenses and other current assets |
134,350 | 293,176 | |||||
Deferred tax asset |
28,335 | 24,245 | |||||
Total current assets |
3,467,078 | 2,770,271 | |||||
Property and equipment, net |
14,763,795 | 15,193,451 | |||||
|
$ | 18,230,873 | $ | 17,963,722 | |||
LIABILITIES, STOCKHOLDERS' EQUITY AND PARENT COMPANY'S INVESTMENT |
|||||||
Current liabilities: |
|||||||
Accounts payable—trade |
$ | 1,462,904 | $ | 419,105 | |||
Accrued expenses and other current liabilities |
1,108,850 | 1,260,740 | |||||
Federal income tax payable |
1,462,503 | 1,744,593 | |||||
Total current liabilities |
4,034,257 | 3,424,438 | |||||
Noncurrent liabilities: |
|||||||
Deferred tax liabilities |
2,491,377 | 2,740,252 | |||||
|
6,525,634 | 6,164,690 | |||||
Commitments and contingencies (Note 7) |
|||||||
Stockholders' equity and parent company's investment: |
|||||||
Common stock, $1 par value, 100 shares authorized, 100 shares issued |
100 | 100 | |||||
Paid in surplus |
65,900 | 65,900 | |||||
Retained earnings |
8,984,110 | 8,311,571 | |||||
Parent company's investment |
2,655,129 | 3,421,461 | |||||
Total stockholders' equity and parent company's investment |
11,705,239 | 11,799,032 | |||||
|
$ | 18,230,873 | $ | 17,963,722 | |||
See accompanying notes to combined financial statements.
F-94
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Combined Statements of Income
Period Ended November 27, 2012 and Year Ended December 31, 2011
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Revenues (including related party revenues of $10,421,940 and $10,565,258 in 2012 and 2011, respectively) |
$ | 20,412,853 | $ | 21,676,963 | |||
Cost and expenses: |
|||||||
Cost of revenues (excluding depreciation and amortization) |
2,478,282 | 1,376,478 | |||||
General and administrative expenses |
3,097,494 | 4,114,454 | |||||
Depreciation |
1,457,661 | 1,620,168 | |||||
Total costs and expenses |
7,033,437 | 7,111,100 | |||||
Operating income |
13,379,416 | 14,565,863 | |||||
Other income (expense): |
|||||||
Interest income |
161 | 243 | |||||
Micellaneous income |
12,480 | 19,130 | |||||
Other income |
12,641 | 19,373 | |||||
Income before tax provision |
13,392,057 | 14,585,236 | |||||
Provision for income taxes |
(4,998,819 | ) | (5,409,518 | ) | |||
Net income |
$ | 8,393,238 | $ | 9,175,718 | |||
See accompanying notes to combined financial statements.
F-95
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Combined Statements of Changes in Stockholders' Equity and Parent Company's Investment
Period Ended November 27, 2012 and Year Ended December 31, 2011
| |
Common Stock | |
|
|
|
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Additional Paid-in Capital |
Retained Earnings |
Parent Company's Investment |
|
|||||||||||||||
| |
Shares | Amount | Total | ||||||||||||||||
Balance, December 31, 2010 |
100 | $ | 100 | $ | 65,900 | $ | 8,360,815 | $ | 4,496,007 | $ | 12,922,822 | ||||||||
Cash dividend paid |
— | — | — | (6,000,000 | ) | (4,299,508 | ) | (10,299,508 | ) | ||||||||||
Net income |
— | — | — | 5,950,756 | 3,224,962 | 9,175,718 | |||||||||||||
Balance, December 31, 2011 |
100 | 100 | 65,900 | 8,311,571 | 3,421,461 | 11,799,032 | |||||||||||||
Cash dividend paid |
— | — | — | (5,000,000 | ) | (3,487,031 | ) | (8,487,031 | ) | ||||||||||
Net income |
— | — | — | 5,672,539 | 2,720,699 | 8,393,238 | |||||||||||||
Balance, November 27, 2012 |
100 | $ | 100 | $ | 65,900 | $ | 8,984,110 | $ | 2,655,129 | $ | 11,705,239 | ||||||||
See accompanying notes to combined financial statements.
F-96
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Combined Statements of Cash Flows
Period Ended November 27, 2012 and Year Ended December 31, 2011
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Cash flow from operating activities: |
|||||||
Net income |
$ | 8,393,238 | $ | 9,175,718 | |||
Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||
Depreciation |
1,457,661 | 1,620,168 | |||||
Deferred income taxes |
(252,965 | ) | (149,159 | ) | |||
Changes in operating assets and liabilities: |
|||||||
Accounts receivable—trade |
(52,581 | ) | 8,389 | ||||
Accounts receivable—related party |
44,895 | 365,804 | |||||
Inventory |
(176,630 | ) | 25,414 | ||||
Prepaid expenses and other assets |
158,826 | (43,377 | ) | ||||
Accounts payable—trade |
1,043,799 | 21,194 | |||||
Accrued expenses and other liabilities |
(151,890 | ) | (227,679 | ) | |||
Federal income taxes payable |
(282,090 | ) | 351,273 | ||||
Net cash provided by operating activities |
10,182,263 | 11,147,745 | |||||
Cash used in investing activities: |
|||||||
Capital expenditures for property, plant, and equipment |
(1,028,005 | ) | (166,920 | ) | |||
Cash used in financing activities: |
|||||||
Dividends paid |
(8,487,031 | ) | (10,299,508 | ) | |||
Net increase in cash |
667,227 | 681,317 | |||||
Cash, beginning of period |
797,450 |
116,133 |
|||||
Cash, end of period |
$ | 1,464,677 | $ | 797,450 | |||
Supplemental Disclosure Information: |
|||||||
Cash paid for federal and state income taxes |
$ | 3,022,393 | $ | 3,625,204 | |||
See accompanying notes to combined financial statements.
F-97
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 1—Organization and Basis of Presentation
Caddo Mills Pipeline Terminal is a cost center of the Truman Arnold Companies (Caddo) which owns and operates a refined petroleum products terminal in Caddo Mills, Texas. Revenues are generated by charging fees to various petroleum product owners for storage and related services. Caddo has a customer base of approximately seven major branded and large independent oil companies.
Arkansas Terminaling and Trading, Inc. (ATT) owns and operates a refined petroleum products terminal in North Little Rock, Arkansas. Revenues are generated by charging fees to various petroleum product owners for storage and related services. ATT has a customer base of approximately twelve major branded and large independent oil companies and refineries.
Collectively, Caddo and ATT will be known as the Company.
The accompanying financial statements are the combined financial statements of Arkansas Terminaling and Trading, Inc and certain carved-out balances of Caddo, which were both affiliated entities under common control of the Truman Arnold Companies until their sale to JP Energy Partners LP on November 27, 2012.
The portion of the accompanying combined financial statements of the Company that are prepared on a "carve-out" basis from Truman Arnold Company's consolidated financial statements reflect the historical accounts directly attributable to Caddo, together with allocations of certain expenses from Truman Arnold Company. The assets of Caddo are recorded at historical cost. Intercompany transactions with Truman Arnold Company have been presented as transactions with affiliates or investment from parent.
Truman Arnold Companies has performed certain corporate functions on behalf of Caddo and the combined financial statements reflect an allocation of the costs Truman Arnold Companies incurred. These functions include executive management, information technology, tax, insurance, accounting, environmental management and legal and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on headcount and percentage of revenue. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had Caddo been operating as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses.
The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP).
Note 2—Summary of Significant Accounting Policies
Use of estimates
The preparation of the combined financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual
F-98
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 2—Summary of Significant Accounting Policies (Continued)
results could differ from these estimates. Significant items subject to such estimates and assumptions include the useful lives of long lived assets, net realizable value of receivables, net realizable value of inventories and environmental liabilities.
Cash and cash equivalents
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. There were no cash equivalents at November 27, 2012 and December 31, 2011.
Concentrations of credit risk
Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. All of our non-interest bearing cash balances were fully insured at November 27, 2012 and December 31, 2011 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.
Accounts receivable
Accounts receivable primarily represent billings for petroleum products pumped through the terminals and are due under normal trade terms requiring payment in 30 days. Management evaluates each customer's credit risk prior to extending credit and does not require collateral. The Company provides for uncollectible accounts under the direct write-off method which, in management's opinion, approximates the allowance method for recording potential bad debts. There were no material bad debts recorded for the period ended November 27, 2012 and the year ended December 31, 2011. Management believes that all significant bad debts, if any, have been recognized as of November 27, 2012 and December 31, 2011.
Property, plant and equipment and related depreciation
Property, plant, and equipment are recorded at cost less accumulated depreciation. Maintenance and repairs are charged to operating expense and any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the account, and any resulting gain or loss is recognized within operating expense. Depreciation is recorded on a straight-line basis over the estimated useful life of the asset.
Inventory
Inventories are stated at the lower of cost or market. Cost is determined by the average cost method, which approximates the first-in, first-out method.
F-99
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 2—Summary of Significant Accounting Policies (Continued)
Impairment of long-lived assets
Long-lived assets such as property and equipment subject to depreciation and amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3 in the Fair Value Hierarchy).
No provision for impairment was recorded for the period ended November 27, 2012 and the year ended December 31, 2011.
Revenue recognition
Revenues are recognized in the period that services are provided or products are delivered.
Due to environmental factors, volumes of products stored on behalf of customers may increase or decrease over time. Such gains or losses are recorded in revenue by the Company as such changes are measured and product is delivered.
Fair value of financial instruments
The Company's combined financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable and accrued expenses. The carrying value of the Company's trade and other receivables, accounts payable and accrued expenses approximates fair value due to their short term maturity.
Income taxes
Caddo is included in the consolidated income tax returns of the Truman Arnold Companies. The provision for income taxes has been prepared as if Caddo filed separate returns and is determined using the asset and liability method in accordance with FASB Codification 740, Income Taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts of existing assets and liabilities in the combined financial statements and their respective tax bases. Future tax benefits of tax loss and tax credit carry forwards are recognized as deferred tax assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled.
Caddo is subject to Texas gross margin tax and recorded $46,271 and $43,507 in state income tax expense as of November 27, 2012 and December 31, 2011, respectively.
F-100
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 2—Summary of Significant Accounting Policies (Continued)
ATT is subject to Arkansas state tax and recorded $617,623 and $622,418 in state tax expense as of November 27, 2012 and December 31, 2011, respectively.
Deferred income taxes on temporary differences between amounts reported for tax and financial reporting relate principally to accelerated depreciation.
ATT is organized as a C Corporation for federal income tax purposes and provides deferred income tax assets and liabilities based on the estimated future tax effects of differences between the financial and tax basis of assets and liabilities based on currently enacted tax laws. The tax balances and income tax expense recognized by the Company are based on management's interpretation of the laws of multiple jurisdictions. Income tax expense also reflects the Company's best estimates and assumptions regarding, among other things, the level of future taxable income, interpretation of the tax laws, and tax planning. Future changes in tax laws, changes in projected levels of taxable income, and tax planning, could affect the effective tax rate and tax balances recorded by the Company. In accordance with FASB ASC 740, tax positions initially need to be recognized in the combined financial statements when it is more-likely-than-not the position will not be sustained upon examination by the tax authorities. At November 27, 2012, the Company is no longer subject to income tax examinations by tax authorities for years prior to December 31, 2008.
At November 27, 2012, the Company had no uncertain tax positions that qualify for either recognition or disclosure in the combined financial statements.
Environmental
Petroleum facilities are subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the removal or mitigation of the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
Note 3—Inventories
Inventories consisted of the following at:
| |
November 27, 2012 |
December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Additive |
$ | 220,514 | $ | 177,094 | |||
Butane |
133,210 | — | |||||
Total inventories |
$ | 353,724 | $ | 177,094 | |||
F-101
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 4—Property, Plant and Equipment, net
Property, plant and equipment consisted of the following at:
| |
Estimated Useful Life |
November 27, 2012 |
December 31, 2011 |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
Land |
— | $ | 766,533 | $ | 766,533 | |||||
Buildings |
10 - 39 years | 238,935 | 238,935 | |||||||
Terminal equipment |
5 - 25 years | 17,961,887 | 17,302,761 | |||||||
Furniture and fixtures |
5 - 20 years | 12,778,835 | 12,602,410 | |||||||
Construction in progress |
— | 241,952 | 41,254 | |||||||
Gross property, plant and equipment |
31,988,142 | 30,951,893 | ||||||||
Less accumulated depreciation |
(17,224,347 | ) | (15,758,442 | ) | ||||||
Property, plant and equipment, net |
$ | 14,763,795 | $ | 15,193,451 | ||||||
Depreciation expense totaled $1,457,661 for 2012 and $1,620,168 for 2011, which is included in depreciation expense in the combined statements of income.
Construction in progress at November 27, 2012 and December 31, 2011 consists primarily of ongoing additions to a DEF tank and will be classified as terminal equipment within property, plant and equipment when completed.
Note 5—Retirement Plan
The Company's employees participate in a noncontributory defined contribution profit sharing plan of Truman Arnold Companies. After meeting eligibility requirements on age, all Company employees are covered. Contributions to this plan are at the discretion of management. The normal policy of the Company is to make an annual contribution at the fiscal year end after a review of the combined financial statements. The contribution for the period ended November 27, 2012 and the year ended December 31, 2011 were $27,923 and $27,630, respectively.
F-102
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 6—Income Taxes
The income tax provision consists of the following.
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Current tax expense: |
|||||||
Federal |
$ | 4,588,190 | $ | 4,890,201 | |||
State |
663,894 | 665,925 | |||||
|
5,252,084 | 5,556,126 | |||||
Deferred federal tax expense (benefit) |
(233,532 | ) | (152,590 | ) | |||
Deferred state tax expense (benefit) |
(19,733 | ) | 5,982 | ||||
|
(253,265 | ) | (146,608 | ) | |||
Provision for income taxes |
$ | 4,998,819 | $ | 5,409,518 | |||
The provision for income tax differs from the amount of income tax determined by applying federal statutory rates to pre-tax income. The difference is primarily due to certain non-deductible expenses.
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Expected tax provision at a 34% rate |
$ | 4,553,300 | $ | 4,958,981 | |||
State income taxes, net of federal tax benefit |
418,437 | 445,492 | |||||
Net effect of nondeductible and non taxable items |
4,656 | 5,045 | |||||
Other |
22,426 | — | |||||
Provision for income taxes |
$ | 4,998,819 | $ | 5,409,518 | |||
The components of deferred taxes at November 27, 2012 and December 31, 2011 are as follows:
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Current deferred tax asset |
|||||||
Tank cleaning reserve |
$ | 9,190 | $ | 5,100 | |||
General insurance reserve |
19,145 | 19,145 | |||||
Total current deferred tax assets |
$ | 28,335 | $ | 24,245 | |||
Long-term deferred tax liability |
|||||||
Excess of net book basis over remaining tax basis (depreciation) |
$ | 2,491,377 | $ | 2,740,252 | |||
F-103
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 7—Commitments and Contingencies
Legal matters
The Company is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company's combined financial position or combined results of operations.
Environmental matters and Asset Retirement Obligations
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Company's activities. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Company accounts for environmental contingencies in accordance with the Financial Accounting Standards Board ASC 410 related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At November 27, 2012 and December 31, 2011, the Company had no significant environmental matters requiring specific disclosure or requiring the recognition of a liability.
Asset retirement obligations include legal or contractual obligations associated with the retirement of tangible long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. We record liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made. Management was not able to reasonably measure the fair value of asset retirement obligations as of November 27, 2012 and December 31, 2011 because settlement dates were indeterminable.
Operating leases
The Company has no operating leases.
F-104
CADDO MILLS PIPELINE TERMINAL
OF TRUMAN ARNOLD COMPANIES &
ARKANSAS TERMINALING AND TRADING, INC.
Notes to Combined Financial Statements (Continued)
Period Ended November 27, 2012 and Year Ended December 31, 2011
Note 8—Related Parties
The related party receivable balances included on the accompanying combined balance sheet represents trade receivables due primarily from Truman Arnold Companies. In addition, at November 27, 2012 and December 31, 2011, the Company had accounts payable-trade and accrued expenses due to Truman Arnold Companies of $47,109 and $16,355, respectively.
The Company also receives revenue from Truman Arnold Companies for storage and related services. During the period ended November 27, 2012 and the year ended December 31, 2011, the Company recognized revenue of $10,421,940 and $10,565,258, respectively, related to services provided to the Truman Arnold Companies.
Prior to November 27, 2012, the Company's assets were pledged as security under the Truman Arnold Companies Senior and Medium Term Notes (collectively, the TAC Notes). As a result of the acquisition of the Company by JP Energy Partners LP described in Note 9, the assets of the Company were released from their lien under the TAC Notes.
Note 9—Subsequent Events
The Company has performed an evaluation of events subsequent to November 27, 2012 and through May 20, 2013, the date the combined financial statements were available to be issued.
The Company was acquired by JP Energy Partners LP on November 27, 2012.
F-105
Report of Independent Registered Public Accounting Firm
To
the Board of Directors and Members of
Falco Energy Transportation, LLC:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in members' capital and cash flows present fairly, in all material respects, the financial position of Falco Energy Transportation, LLC and its subsidiaries at July 19, 2012 and December 31, 2011, and the results of their operations and their cash flows for the period from January 1, 2012 to July 19, 2012 and the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/
PricewaterhouseCoopers LLP
Dallas,
Texas
July 3, 2013
F-106
Falco Energy Transportation, LLC
Consolidated Balance Sheets
| |
July 19, 2012 |
December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Assets |
|||||||
Current assets |
|||||||
Cash |
$ | 222,541 | $ | 1,009,058 | |||
Accounts receivable |
5,204,382 | 3,263,803 | |||||
Related party receivables |
6,815 | 52,762 | |||||
Prepaids and other current assets |
731,533 | 988,159 | |||||
Customer deposits and advances |
193,237 | 161,519 | |||||
Total current assets |
6,358,508 | 5,475,301 | |||||
Property, plant and equipment, net (Note 3) |
12,179,320 | 12,658,325 | |||||
Intangible assets |
61,468 | 85,932 | |||||
Investment in affiliate (Note 4) |
— | 597,207 | |||||
Debt issuance costs |
64,379 | 72,804 | |||||
Total assets |
$ | 18,663,675 | $ | 18,889,569 | |||
Liabilities and Members' Equity |
|||||||
Current liabilities |
|||||||
Bank overdraft |
$ | 829,860 | $ | 300,854 | |||
Accounts payable |
811,708 | 1,410,133 | |||||
Accrued liabilities (Note 5) |
2,067,915 | 2,509,837 | |||||
Payable to affiliate |
557,708 | 21,555 | |||||
Related party payables |
188,808 | 132,377 | |||||
Current maturities of long-term liabilities (Note 6) |
6,421,566 | 4,817,600 | |||||
Total current liabilities |
10,877,565 | 9,192,356 | |||||
Long-term liabilities (Note 6) |
4,790,160 | 5,596,210 | |||||
Total liabilities |
15,667,725 | 14,788,566 | |||||
Commitments and contingencies (Note 8) |
|||||||
Total members' capital |
2,995,950 | 4,101,003 | |||||
Total liabilities and members' capital |
$ | 18,663,675 | $ | 18,889,569 | |||
See accompanying notes to consolidated financial statements.
F-107
Falco Energy Transportation, LLC
Consolidated Statements of Operations
| |
Period from January 1, 2012 to July 19, 2012 |
Year ended December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Revenues |
$ | 22,965,550 | $ | 33,312,021 | |||
Cost of sales, operating, and administrative expenses: |
|||||||
Cost of sales, excluding depreciation and amortization |
18,064,830 | 25,156,925 | |||||
Operating expenses |
2,317,700 | 3,491,600 | |||||
General and administrative |
1,387,078 | 1,620,672 | |||||
Depreciation and amortization |
1,377,798 | 2,007,829 | |||||
Gain on disposal of assets |
(31,774 | ) | (21,086 | ) | |||
Operating income (loss) |
(150,082 | ) | 1,056,081 | ||||
Other income (expense): |
|||||||
Interest expense |
(314,599 | ) | (462,564 | ) | |||
Equity earnings (loss) in affiliate |
(172,039 | ) | 21,201 | ||||
Income (loss) before income taxes |
(636,720 | ) | 614,718 | ||||
State income tax expense |
(43,955 | ) | (63,037 | ) | |||
Net income (loss) |
$ | (680,675 | ) | $ | 551,681 | ||
See accompanying notes to consolidated financial statements.
F-108
Falco Energy Transportation, LLC
Consolidated Statements of Changes in Members' Capital
| |
Units | Members' Capital | |||||
|---|---|---|---|---|---|---|---|
Balance, at January 1, 2011 |
1,000 | $ | 3,549,322 | ||||
Net Income |
— | 551,681 | |||||
Balance, at December 31, 2011 |
1,000 | $ | 4,101,003 | ||||
Net loss |
— | (680,675 | ) | ||||
Distribution of investment in affiliate to members |
— | (424,378 | ) | ||||
Balance, at July 19, 2012 |
1,000 | $ | 2,995,950 | ||||
See accompanying notes to consolidated financial statements.
F-109
Falco Energy Transportation, LLC
Consolidated Statements of Cash Flows
| |
Period from January 1, 2012 to July 19, 2012 |
Year ended December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Cash flows from operating activities |
|||||||
Net (loss) income |
$ | (680,675 | ) | $ | 551,681 | ||
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities: |
|||||||
Depreciation and amortization |
1,377,798 | 2,007,829 | |||||
Gain on disposal of assets |
(31,774 | ) | (21,086 | ) | |||
Equity loss (earnings) in affiliate |
172,039 | (21,201 | ) | ||||
Amortization of debt issuance costs |
8,425 | 33,323 | |||||
Changes in operating assets and liabilities: |
|||||||
Accounts receivables |
(1,940,580 | ) | (1,718,338 | ) | |||
Related party receivables |
45,947 | (52,762 | ) | ||||
Prepaids and other current assets |
256,626 | (379,019 | ) | ||||
Customer deposits and advances |
(31,718 | ) | (58,851 | ) | |||
Accounts payable and accrued liabilities |
(1,040,347 | ) | 1,710,736 | ||||
Payable to affiliate |
536,155 | 39,143 | |||||
Related party payables |
56,431 | 124,626 | |||||
Net cash used in (provided by) operating activities |
(1,271,673 | ) | 2,216,081 | ||||
Cash flows from investing activities |
|||||||
Purchase of property, plant, and equipment |
(657,591 | ) | (2,226,315 | ) | |||
Contributions to equity affiliate |
— | (93,425 | ) | ||||
Proceeds from sale of assets |
371,314 | 249,725 | |||||
Other investing activities |
(5,131 | ) | (21,100 | ) | |||
Net cash used in investing activities |
(291,408 | ) | (2,091,115 | ) | |||
Cash flows from financing activities |
|||||||
Proceeds from line of credit |
12,841,564 | 21,221,465 | |||||
Payments on line of credit |
(11,159,533 | ) | (20,964,599 | ) | |||
Proceeds from long-term debt |
25,881 | 7,017,086 | |||||
Payments on long-term debt |
(1,460,354 | ) | (7,930,313 | ) | |||
Changes from bank overdraft |
529,006 | 300,854 | |||||
Payment for debt issuance costs |
— | (96,583 | ) | ||||
Net cash provided by (used in) financing activities |
776,564 | (452,090 | ) | ||||
Net decrease in cash |
(786,517 | ) | (327,124 | ) | |||
Cash, beginning of period |
1,009,058 | 1,336,182 | |||||
Cash, end of period |
$ | 222,541 | $ | 1,009,058 | |||
Supplemental Cash Flow Information |
|||||||
Cash paid for interest |
$ | 268,905 | $ | 413,892 | |||
Cash paid for state income taxes |
$ | 33,893 | $ | — | |||
Supplemental Non-Cash Disclosure Information |
|||||||
Financed additions of property, plant, and equipment |
$ | 550,356 | $ | 2,699,296 | |||
Distribution of investment in affiliate to members |
$ | 424,378 | $ | — | |||
See accompanying notes to consolidated financial statements.
F-110
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements
1. Organization and Basis of Presentation
Falco Energy Transportation, LLC ("Falco" or the "Company") was formed on April 12, 2007. The Company is engaged in the transportation of crude oil with locations in Shreveport, LA, Williston, ND, Casper, WY and Gillette, WY. The Company is a limited liability company ("LLC") under the laws of Delaware.
The Company owns 100% of the following related companies:
- •
- Falcon Applications, LLC, located in Shreveport, LA and provides software design services to the Company as well as
third party customers;
- •
- Falco STX, LLC, located in Pearsall, TX and is primarily in the business of sub-contracting crude oil hauling;
- •
- Falco TPH, LLC, located in Shreveport, LA and is primarily in the business of sub-contracting crude oil hauling for
the Company;
- •
- ND Land Holdings, LLC, located in Shreveport, LA and owns land in North Dakota that houses one of the Company's
locations; and
- •
- Falco STX Land Holdings, LLC, owns land located in Pearsall, TX that houses Falco STX, LLC.
Prior to July 19, 2012, the Company owned 30% interest in Falco Texoma, LLC ("Texoma") and this investment is accounted for using the equity method of accounting. On July 19, 2012, the Company's interest in Texoma was distributed to a company owned by the members of the Company, as discussed in Note 4.
Prior to July 19, 2012, the Company was owned by EIV Capital Fund, LP, Falco Crude Services, LLC, Belle Fourche Holdings, LLC and Pine Energies, LLC (collectively, the "members"') in the percentages of 50%, 16.667%, 16.667% and 16.666%, respectively. On July 19, 2012, the Company was acquired by JP Energy Partners ("JPE"), as discussed in Note 10.
The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP").
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of the financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Cash
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. There were no cash equivalents at July 19, 2012 and December 31, 2011. The Company places its temporary cash investments with high quality financial institutions. At times, such investments may be in excess of Federal Deposit Insurance Corporation (FDIC) insurance limits.
F-111
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
Major Customers and Suppliers
Concentrations of customers impact the Company's overall exposure to credit risk, either positively or negatively. No single supplier accounted for 10% or more of total purchases, but the following customers represent more than 10% of total revenue as indicated below.
Revenue
|
Period from January 1, 2012 to July 19, 2012 |
For the year ended December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Unaffiliated |
|||||||
Energy marketing company |
64% | 71% | |||||
Integrated crude oil producer |
16% | 21% | |||||
Integrated crude oil producer |
11% | 2% | |||||
This concentration of revenue may impact the Company's overall operations either positively or negatively. Although no assurances can be given that the significant customers will remain solvent and continue their current business relationship with the Company, the Company expects its relationships with its first and third largest customers to continue. The contract with the second largest customer in 2012 expired in October 2012 and was not renewed.
Concentrations of Credit Risk
Cash is maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. All of the Company's non-interest bearing cash balances were fully insured at July 19, 2012 and December 31, 2011 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage reverted to $250,000 per depositor at each financial institution.
Accounts Receivable
Accounts receivable are reported net of the allowance for doubtful accounts. Management estimates that allowance for doubtful accounts is based on specific identification and historical collection results. Account balances are charged against the allowance when it is anticipated that the receivable will not be collected. The balance is considered past due or delinquent based on contractual terms with the customer.
There was no allowance for doubtful accounts as of July 19, 2012 and December 31, 2011.
Property, Plant and Equipment and Related Depreciation
Property, plant, and equipment are recorded at cost less accumulated depreciation. Maintenance and repairs for trucks and trailers are charged to cost of sales and any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. Depreciation is recorded on a straight-line basis over the estimated useful life of the asset. Additionally, depreciation and amortization is disclosed separately within the consolidated statements of operations.
F-112
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
Intangible Assets
Intangible assets consist of software for internal use developed by the Company. All costs are charged to operating expenses in the initial project stage, and the costs of the development stage are capitalized when certain criteria are met. Internal use software is amortized over its useful life of 3 years. Annual amortization of the balance at July 19, 2012 of $61,468 over the next three years is expected to be $11,674 for July 20 through December 31, 2012, $36,138 in 2013, and $13,656 in 2014. The amounts are presented within depreciation and amortization expense in the consolidated statements of operations.
Impairment of Long-Lived Assets
Long-lived assets such as property and equipment, and purchased intangible assets subject to depreciation and amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. When the carrying amount exceeds undiscounted cash flows, impairment is recognized to the extent that the carrying value exceeds its fair value. No impairment was recognized during the period of January 1, 2012 to July 19, 2012 or during 2011.
Debt Issuance Costs
The Company capitalizes all direct costs incurred in connection with the issuance of debt as debt issuance costs. These costs are amortized over the contractual term of the debt instrument using the effective interest or straight-line method, as appropriate.
Equity Accounting
The Company accounts for investments over which it has significant influence but does not control using the equity method of accounting. Under the equity method of accounting, the Company recognizes its share of the investee's earnings in Equity earnings / (loss) in affiliate. Contributions made to the investee increase the recorded investment, and distributions received from the investee reduce the recorded investment. The Company assesses impairment of its investment in affiliate when circumstances indicate it may be other than temporarily impaired.
Revenue Recognition
The Company is in the business of transporting crude oil. Revenues from such transportation are recognized upon completion of the transportation at the time of delivery to the customers. The Company routinely enters into transactions to purchase crude oil from, and sell crude oil to, the same counterparty. Such transactions that are entered into in contemplation of one another are recorded on a net basis. Revenues from providing capacity on pipelines owned by third parties and other associated fees are recognized at the point of delivery. The Company also contracts with third party hauling companies to haul crude oil under its customer contracts. The costs paid to the third party hauling companies are charged to the Company's customers and are recorded as revenue. In addition the Company earns a fixed fee to manage these third party relationships.
F-113
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash, trade and other receivables, accounts payable, accrued expenses, and other long term liabilities. The carrying amount of the Company's trade and other receivables, accounts payable and accrued expenses approximate fair value due to their short term maturity. The carrying amount reported for long-term debt and other long term liabilities does not approximate fair value because the underlying instruments are at rates higher than the current rates offered to the Company for debt with the same remaining maturities.
Income Taxes
All components of these consolidated financial statements are derived from the financial information of "flow-through" entities (e.g. LLCs or LPs) treated as partnerships for federal income tax purposes. The Company is subject to Texas Margin Tax ("TMT"), which totaled $43,995 for the period from January 1, 2012 to July 19, 2012 and $63,037 for the year ended December 31, 2011 which is presented as state income tax expense on the consolidated statement of operations. Additionally, all income taxes payable as of July 19, 2012 and December 31, 2011 are recorded within accrued liabilities in the consolidated balance sheets.
Comprehensive Income/Loss
For the period from January 1, 2012 to July 19, 2012, comprehensive loss equaled net loss. For the year ended December 31, 2011, comprehensive income equaled net income.
Consolidations
The consolidated financial statements include the accounts and transactions of the Company and its subsidiaries. Intercompany balances and transactions have been eliminated from the consolidated financial statements as part of the consolidation process.
3. Property, plant and equipment, net
Property, plant and equipment, net are comprised of the following at July 19, 2012 and December 31, 2011:
| |
Estimated Useful Life | July 19, 2012 | 2011 | ||||||
|---|---|---|---|---|---|---|---|---|---|
Land |
— | $ | 283,060 | $ | 268,927 | ||||
Building and improvements |
15-39 years | 981,327 | 957,907 | ||||||
Machinery and equipment |
5-7 years | 726,762 | 726,762 | ||||||
Trucks and trailers |
5-7 years | 15,650,371 | 15,098,047 | ||||||
Office furniture and equipment |
3-7 years | 210,581 | 137,413 | ||||||
Gross property, plant and equipment |
17,852,101 |
17,189,056 |
|||||||
Less accumulated depreciation |
(5,672,781 | ) | (4,530,731 | ) | |||||
Property, plant and equipment, net |
$ | 12,179,320 | $ | 12,658,325 | |||||
F-114
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
3. Property, plant and equipment, net (Continued)
Depreciation expense totaled $1,357,883 for the period from January 1, 2012 to July 19, 2012 and $1,986,748 for the year ended December 31, 2011, and is included in depreciation and amortization expense in the consolidated statements of operations.
Certain plant, property, and equipment owned by the Company is used as collateral for financing discussed further in Note 6. The carrying value of these plant, property and equipment at July 19, 2012 and December 31, 2011 is $3,024,913 and $2,699,296, respectively.
4. Investment in affiliate
Prior to July 19, 2012, the Company had a 30% interest in Texoma, which was accounted for using the equity method of accounting. On July 19, 2012, the Company's interest in Texoma was distributed to an entity owned by the members of the Company. The carrying amount of the investment in Texoma reduced member's capital and has been reflected as a distribution to members in the consolidated statement of changes in members' capital.
The Company provided certain marketing and administrative services to Texoma including accounting, marketing for major crude oil producers, certain daily management activities, training and information technology support under the Texoma Supply Agreement dated May 27, 2010 ("Supply Agreement"). The Supply Agreement has been terminated upon the distribution of the Company's interest in the Texoma partnership on July 19, 2012. The total income from these services recognized by the Company was $26,839 and $78,920 for the period from January 1, 2012 to July 19, 2012 and for the year ended December 31, 2011, respectively, and is recorded as revenue on the consolidated statement of operations. The Company also had a balance due to Texoma of $557,708 as of July 19, 2012 and a balance due to Texoma of $21,555 as of December 31, 2011. The amount payable as of July 19, 2012 and December 31, 2011 are presented as payable from affiliate on the consolidated balance sheets as of the respective periods.
The Company has contracts to haul crude oil with certain customers who have leases within the Area of Mutual Interest ("AMI"), as defined in the Supply Agreement dated May 27, 2010 where Texoma operates. Under this arrangement the crude oil transportation within the AMI is solely performed by Texoma. As the Company is the primary obligator to its customers, the Company has recognized revenue for these transactions revenue in the amount of $2,723,773 for the period from January 1, 2012 to July 19, 2012 and $2,676,654 in 2011. The Company also recorded cost of sales in the same amount for the service provided by Texoma.
The Company also provided drivers and trucks for Texoma's use. The drivers and trucks are provided on a direct cost recovery basis and the Company earns no margin for these activities. During the period from January 1, 2012 to July 19, 2012 and for the year ended December 31, 2011, the total cost recovered from Texoma for these activities was $302,516 and $804,675, respectively, which are recorded within cost of sales, excluding depreciation and amortization on the consolidated statements of operations. In addition to the costs recovered, the Company also made contributions to Texoma in the amount of $93,425 for the year ended December 31, 2011. There were no contributions to the affiliate during the period from January 1, 2012 to July 19, 2012.
The carrying amount of the investment in Texoma was $0 at July 19, 2012 and $597,207 at December 31, 2011.
F-115
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
5. Accrued liabilities
Accrued liabilities are comprised of the following at July 19, 2012 and December 31, 2011:
| |
July 19, 2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Wages and employee benefits |
$ | 783,214 | $ | 1,333,467 | |||
Third party trucking payable |
431,807 | 668,511 | |||||
Insurance related payables |
644,393 | 333,233 | |||||
Accrued capital expenditures |
57,797 | 96,242 | |||||
Accrued state income taxes payable |
106,992 | 63,037 | |||||
Other |
43,712 | 15,347 | |||||
Total accrued liabilities |
$ | 2,067,915 | $ | 2,509,837 | |||
6. Long-term liabilities
Long-term liabilities are comprised of the following at July 19, 2012 and December 31, 2011:
| |
July 19, 2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Notes payable to Ford Credit |
$ | 204,940 | $ | 197,579 | |||
Notes payable to F&M Bank & Trust Company |
6,523,487 | 7,204,724 | |||||
Community Trust Bank note payable |
427,304 | 437,391 | |||||
Community Trust Bank line of credit |
3,938,887 | 2,256,856 | |||||
Notes Payable to Ally Bank |
117,108 | — | |||||
Financed insurance premiums |
— | 317,260 | |||||
Total debt |
11,211,726 | 10,413,810 | |||||
Less current portion |
(6,421,566 | ) | (4,817,600 | ) | |||
Total long-term liabilities |
$ | 4,790,160 | $ | 5,596,210 | |||
On February 10, 2011, the Company repaid all outstanding debt with Compass Bank related to machinery, equipment, truck, and trailer purchases made in prior years on a non-recourse basis. All loans originated during 2011 to purchase additional trucks and trailers were also on a non-recourse basis. As of July 19, 2012, the Company has $7,272,839 of long term notes payable which includes $6,523,487 not personally guaranteed by the members of the Company. As of December 31, 2011, the Company had $7,839,694 in long term notes payable which included $7,204,724 not personally guaranteed by the members of the Company.
Terms for the notes payable with the applicable counterparties as of July 19, 2012 and December 31, 2011 follow:
Counterparty
|
Maturity Dates | Interest Rates | Collateralized by | |||||
|---|---|---|---|---|---|---|---|---|
Ford Credit |
12/2013 to 12/2016 | 4.74% to 8.89% | Vehicles | |||||
F&M Bank & Trust Co. |
2/2015 to 5/2017 | Prime plus 0.50% | Equipment | |||||
Ally Bank |
7/2016 to 4/2018 | 0.00% to 5.24% | Vehicles | |||||
Community Trust Bank |
4/2014 | 5.5% | Real Property | |||||
F-116
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
6. Long-term liabilities (Continued)
The maturities of long term debt for each of the next 5 years as of July 19, 2012 are as follows:
| |
July 19, 2012 | |||
|---|---|---|---|---|
Remainder of 2012 |
$ | 6,421,566 | ||
2013 |
2,052,287 | |||
2014 |
1,414,060 | |||
2015 |
1,007,441 | |||
2016 |
314,405 | |||
Thereafter |
1,967 | |||
Total long-term liabilities |
$ | 11,211,726 | ||
On February 11, 2011, the Company executed a revolving credit agreement with Community Trust Bank providing for maximum borrowing of $3,001,530. In April 2012, the Company renewed the revolving credit agreement with Community Trust Bank, expanding the maximum borrowing to $4,000,000. The loan has a variable based on LIBOR plus 2.95% with a minimum interest rate of 4.5%. The outstanding balance as of July 19, 2012 is $3,938,887 resulting in $61,113 in additional borrowing capacity. The outstanding balance as of December 31, 2011 was $2,256,856. As discussed in Note 10, this revolving line of credit was paid in full as part of the acquisition of the Company by JPE in July 2012.
7. Income Taxes
The Company is a Delaware limited liability company that has elected to be treated as a partnership for tax purposes and is not subject to federal income taxes; rather the taxable earnings or losses are reported by the members in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these consolidated financial statements.
The Company recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Company has evaluated tax positions taken or expected to be taken in the course of preparing the Company's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority.
The Company follows the guidance for accounting for uncertainty in income taxes in accordance with Accounting Standards Codification ("ASC") 740, which clarifies uncertainty in income taxes recognized in an enterprise's financial statements. The standard also prescribes a recognition threshold and measurement standard for the financial statement recognition and measurement of an income tax position taken, or expected to be taken, in an income tax return. Only tax positions that meet the more likely than not recognition threshold may be recognized. In addition, the standard provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, and disclosure. The total amount of uncertain tax liabilities as of July 19, 2012 is $66,909 and $34,014 as of December 31, 2011.
F-117
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
8. Commitments and Contingencies
Legal Matters
The Company is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company's financial position, results of operations, and cash flows.
Environmental Matters and Asset Retirement Obligations
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Company's activities. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Company accounts for environmental contingencies in accordance with the ASC 410, "Asset Retirements and Environmental Obligations" related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At July 19, 2012 and December 31, 2011, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Asset retirement obligations include legal or contractual obligations associated with the retirement of tangible long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. We record liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made. Management was not able to reasonably measure the fair value of asset retirement obligations as of July 19, 2012 and December 31, 2011 because settlement dates were indeterminable.
Operating Leases
The Company leases land, buildings, office space, and equipment under non-cancellable operating leases. The Company's aggregate rental expense for such leases was $739,291 for the period from January 1, 2012 to July 19, 2012 and $682,811 for the year ended December 31, 2011.
F-118
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
8. Commitments and Contingencies (Continued)
Minimum future payments under non-cancelable operating leases as of July 19, 2012 are as follows:
Remainder of 2012 |
$ | 104,421 | ||
2013 |
220,713 | |||
2014 |
112,270 | |||
Total minimum operating lease payments |
$ | 437,404 | ||
9. Related Parties
The Company had the following related party receivables as of July 19, 2012 and December 31, 2011:
| |
July 19, 2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Due from Scott Smith III |
$ | 1,538 | $ | 1,588 | |||
Due from Falco Disposal Systems |
4,857 | 51,174 | |||||
Other |
420 | — | |||||
Total |
$ | 6,815 | $ | 52,762 | |||
The Company had the following related party payables as of July 19, 2012 and December 31, 2011:
| |
July 19, 2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Due to Energy Trucking, LLC |
$ | 188,808 | $ | 132,377 | |||
Total |
$ | 188,808 | $ | 132,377 | |||
The Company made reimbursements for certain costs to Belle Fourche Holdings, LLC, a company that owns approximately 16.667% of the Company's membership interest as discussed in Note 1. The total amount of the reimbursement of costs made to Belle Fourche Holdings, LLC is $908 for the period from January 1, 2012 to July 19, 2012 and $0 for the year ended December 31, 2011.
The Company made payments to Scott Smith III, its President and CEO for compensation and guarantee fees. The total amount of the payments made to Scott Smith III was $159,437 for the period from January 1, 2012 to July 19, 2012 and $207,371 for the year ended December 31, 2011. Additionally, as of July 19, 2012 and December 31, 2011, Scott Smith III also had payables due to the Company of $1,538 and $1,588, respectively.
Three of the Company's members also own another entity, Falco Disposal Systems, LLC, which operates a salt water disposal well in Texas. The Company processes payroll and performs various administrative activities on behalf of Falco Disposal Systems, LLC. The Company is reimbursed for all direct expenses totaling $30,850 from January 1, 2012 to July 19, 2012 and $68,479 in 2011.
The Company entered into operating leases with Energy Trucking, LLC ("Energy Trucking"), a company that is owned 100% by EIV Capital Fund, LP, during 2011 to obtain trucks and trailers. As a result of these operating lease agreements with Energy Trucking, the Company made lease payments to Energy Trucking in the amounts of $349,720 and $279,670 for the period from January 1, 2012 to
F-119
Falco Energy Transportation, LLC
Notes to Consolidated Financial Statements (Continued)
9. Related Parties (Continued)
July 19, 2012 and the year ended December 31, 2011, respectively. In connection with these lease payments, the Company also had outstanding payables related to these operating leases due to Energy Trucking of $188,808 and $132,377 as of July 19, 2012 and December 31, 2011, respectively. These outstanding payable amounts have been disclosed as related party payables within the consolidated balance sheets. On July 19, 2012, as part of the acquisition by JPE, the Company acquired the trucks and trailers previously under lease through Energy Trucking for $2,548,917.
10. Subsequent Events
The Company has performed an evaluation of subsequent events through July 2nd, 2013 which is the date the consolidated financial statements were issued. The following events were identified by the Company subsequent to July 19, 2012:
The Company was acquired by JPE on July 19, 2012. In conjunction with the acquisition of the Membership Interests of the Company, the members were required to pay off certain outstanding debt balances and to assume the debt related to certain other debt positions as of closing of the transaction. The members of the Company paid off the Community Trust Bank Line of Credit, Community Trust Mortgage, the Notes Payable to Ally Bank, and the Notes Payable to Ford Financial in the amounts of $3,938,887, $427,304, $117,108, and $204,940, respectively, upon closing of the transaction from the proceeds received.
Immediately subsequent to the acquisition of the Company by JPE, JPE executed an amended and restated credit agreement with F&M Bank & Trust Company. This amended and restated credit agreement modified the debt covenants to list JPE as the borrower and, as such, JPE's financial statements are now used to determine the applicable covenants. For the period ended July 19, 2012, JPE obtained a waiver from F&M Bank & Trust Company for noncompliance to provide lender with timely notification of default, erroneous financial statements and with agreed covenants in general.
F-120
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board
of Directors
JP Energy Partners LP
We have audited the accompanying balance sheets of Heritage Propane Express, LLC as of June 6, 2012 and December 31, 2011 and the related statements of operations, parent's equity in division, and cash flows for the period from January 1, 2012 to June 6, 2012 and the year ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Heritage Propane Express, LLC as of June 6, 2012 and December 31, 2011, and the results of its operations and its cash flows for the period from January 1, 2012 to June 6, 2012 and the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Kansas
City, Missouri
May 20, 2013
F-121
Heritage Propane Express, LLC
Balance Sheets
| |
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Assets |
|||||||
Current assets |
|||||||
Cash |
$ | 7,201,868 | $ | 1,324,463 | |||
Accounts receivable, net |
5,799,684 | 3,291,351 | |||||
Accounts receivable, related party |
44,071 | — | |||||
Inventories |
2,419,737 | 3,381,778 | |||||
Prepaids and other current assets |
3,170,257 | 3,491,424 | |||||
Total current assets |
18,635,617 | 11,489,016 | |||||
Property, plant and equipment, net |
43,831,017 | 40,773,723 | |||||
Goodwill |
3,619,252 | 3,619,252 | |||||
Intangible assets, net |
6,040,187 | 6,221,691 | |||||
Other assets |
5,275 | 5,275 | |||||
Total assets |
72,131,348 | 62,108,957 | |||||
Liabilities and Equity |
|||||||
Current liabilities |
|||||||
Accounts payable—trade |
3,097,105 | 615,039 | |||||
Accrued liabilities |
5,784,127 | 4,282,049 | |||||
Price risk management liabilities |
1,764,129 | — | |||||
Customer deposits and advances |
106,783 | 146,181 | |||||
Current portion of long-term liabilities |
174,205 | 174,205 | |||||
Total current liabilities |
10,926,349 | 5,217,474 | |||||
Long-term liabilities |
875,478 | 440,644 | |||||
Commitments and contingencies (Note 14) |
|||||||
Total liabilities |
11,801,827 |
5,658,118 |
|||||
Equity |
|||||||
Parent's Equity in Division |
60,329,521 | 56,450,839 | |||||
Total liabilities and equity |
$ | 72,131,348 | $ | 62,108,957 | |||
The accompanying notes are an integral part of these financial statements.
F-122
Heritage Propane Express, LLC
Statements of Operations
| |
Period from January 1 2012 to June 6, 2012 |
Year ended December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Revenues |
$ | 24,862,210 | $ | 51,045,974 | |||
Costs and expenses |
|||||||
Costs of sales (excluding depreciation and amortization) |
12,504,786 | 23,736,370 | |||||
Operating expenses |
11,640,174 | 18,868,220 | |||||
General and administrative expenses |
284,736 | 2,332,315 | |||||
Depreciation and amortization expense |
2,184,746 | 5,171,960 | |||||
Loss on disposal of assets |
444,724 | 1,088,491 | |||||
Total costs and expenses |
27,059,166 | 51,197,356 | |||||
Operating loss |
(2,196,956 | ) | (151,382 | ) | |||
Other expenses: |
|||||||
Interest expense |
(11,347 | ) | (16,351 | ) | |||
Loss before income taxes |
(2,208,303 | ) | (167,733 | ) | |||
Income taxes |
(15,450 | ) | (37,066 | ) | |||
Net loss |
$ | (2,223,753 | ) | $ | (204,799 | ) | |
The accompanying notes are an integral part of these financial statements.
F-123
Heritage Propane Express, LLC
Statements of Parent's Equity in Division
| |
Parent's Equity in Division |
|||
|---|---|---|---|---|
Balance, at January 1, 2011 |
$ | 45,804,122 | ||
Net investment from parent |
10,851,516 | |||
Net loss |
(204,799 | ) | ||
Balance, at December 31, 2011 |
56,450,839 | |||
Net investment from parent |
6,102,435 | |||
Net loss |
(2,223,753 | ) | ||
Balance, at June 6, 2012 |
$ | 60,329,521 | ||
The accompanying notes are an integral part of these financial statements.
F-124
Heritage Propane Express, LLC
Statements of Cash Flows
| |
Period from January 1, 2012 to June 6, 2012 |
Year ended December 31, 2011 |
|||||
|---|---|---|---|---|---|---|---|
Cash flows from operating activities |
|||||||
Net loss |
$ | (2,223,753 | ) | $ | (204,799 | ) | |
Adjustments to reconcile net loss to net cash provided by operating activities: |
|||||||
Depreciation and amortization |
2,184,746 | 5,171,960 | |||||
Loss on disposal of assets |
444,724 | 1,088,491 | |||||
Unrealized loss on price risk management liabilities |
1,658,973 | — | |||||
Provision for losses on accounts receivable |
9,971 | 208,682 | |||||
Gains on acquisition bargain purchases |
— | (289,839 | ) | ||||
Changes in operating assets and liabilities, net of acquisitions: |
|||||||
Accounts receivable |
(2,518,304 | ) | 56,591 | ||||
Accounts receivable—related party |
(44,071 | ) | — | ||||
Inventories |
962,041 | (435,693 | ) | ||||
Prepaids and other current assets |
321,167 | 909,632 | |||||
Other long-term assets |
— | (154,640 | ) | ||||
Accounts payable—trade |
2,482,066 | (305,034 | ) | ||||
Customer advances and deposits |
(39,398 | ) | 34,255 | ||||
Accrued liabilities |
1,532,704 | (1,199,430 | ) | ||||
Net cash provided by operating activities |
4,770,866 | 4,880,176 | |||||
Cash flows from investing activities |
|||||||
Cash paid for acquisitions, net of cash acquired |
— | (7,092,739 | ) | ||||
Purchase of property, plant and equipment |
(7,185,667 | ) | (10,607,302 | ) | |||
Proceeds from the sale of assets |
1,680,407 | 2,970,034 | |||||
Net cash used in investing activities |
(5,505,260 | ) | (14,730,007 | ) | |||
Cash flows from financing activities |
|||||||
Principals payments on debt |
— | (117,027 | ) | ||||
Net investment by parent |
6,611,799 | 10,851,516 | |||||
Net cash provided by financing activities |
6,611,799 | 10,734,489 | |||||
Net increase in cash |
5,877,405 | 884,658 | |||||
Cash, beginning of period |
1,324,463 | 439,805 | |||||
Cash, end of period |
$ | 7,201,868 | $ | 1,324,463 | |||
The accompanying notes are an integral part of these financial statements.
F-125
Heritage Propane Express, LLC
Notes to Financial Statements
1. Organization and Basis of Presentation
Heritage Propane Express, LLC, a Delaware limited liability company ("HPX" or "the Company") is a full service provider of propane grill cylinders for exchange for retailers and/or distributors. HPX has production facilities, districts, and depots in its marketing areas that refurbish, deliver, and distribute to the retailer. In addition to propane cylinders, HPX provides services such as quality storage cabinets, safety protection, safety and marketing training, and unique marketing branding enabling the retailer to provide point of purchase sales of both exchange and new propane grill cylinders. HPX conducts a national propane distribution business through its distribution network in 44 states.
Until December 31, 2011, HPX's business was a division of Heritage Operating, L.P. ("HOLP"). Prior to January 1, 2012, the Company's assets secured the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (Collectively, the "HOLP Notes"). On January 1, 2012, the division was distributed in a common control transaction by HOLP to HPX formed on December 1, 2011 as a separate legal entity and an indirectly wholly-owned subsidiary of Energy Transfer Partners, L.P. ("ETP") when the assets of HPX were released from their lien of the HOLP Notes. ETP owned an indirect 100% Limited Partner interest in HOLP until ETP's sale of HOLP on January 12, 2012 to AmeriGas Partners, L.P. ("AmeriGas"). HPX was then acquired from ETP by JP Energy Partners LP on June 7, 2012 and was subsequently renamed Pinnacle Propane Express, LLC.
Due to the common control transaction, the financial statements of HPX report the results of operations as though the transfer of net assets had occurred at the beginning of 2011. The accompanying 2011 financial statements of the Company that are prepared on a "carve-out" basis from the consolidated financial statements of HOLP reflect the historical accounts directly attributable to HPX, together with allocations of certain expenses from HOLP. The assets of HPX are recorded at historical cost. All significant intra-company accounts and transactions have been eliminated in the financial statements. Intercompany transactions with HOLP have been presented as transactions with related parties in 2012.
In 2011, HOLP performed certain corporate functions on behalf of HPX and the financial statements reflect an allocation of the costs HOLP incurred. These functions included human resources, information technology, tax, insurance, accounting, legal, and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on payroll and revenues. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had HPX been operating as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses.
In 2012, AmeriGas provided HPX with certain services including, among others, human resources, information technology, tax, legal, insurance and treasury services pursuant to a Cylinder Exchange Transition Agreement ("TSA") between HPX, AmeriGas and ETP. HPX expensed $284,736 in connection with such services which was included in general and administration expenses in 2012.
The accompanying financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP).
F-126
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
2. Summary of Significant Accounting Policies
Use of estimates
The preparation of the financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant items subject to such estimates and assumptions include the useful lives of long lived assets, impairment analysis, fair value of assets and liabilities of acquisitions and allowance for doubtful accounts.
Concentrations of Credit Risk
Cash is maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. All of our non-interest bearing cash balances were fully insured at June 6, 2012 and December 31, 2011 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage will revert to $250,000 per depositor at each financial institution.
Major Customers and Suppliers
Concentrations of customers impact our overall exposure to credit risk, either positively or negatively. Management believes that our portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. No single customer accounted for 10% or more of our revenue or accounts receivable.
We had gross purchases as a percentage of total purchases from major suppliers as follows:
| |
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Unaffiliated |
|||||||
Martin |
27.3 | % | 28.9 | % | |||
Smith |
49.7 | % | 45.2 | % | |||
NGR |
— | 15.0 | % | ||||
Affiliated |
|||||||
Enterprise |
10.8 | % | 9.5 | % | |||
Enterprise Products Partners L.P. together with its subsidiaries ("Enterprise") is a related party as discussed in Note 15. This concentration of supplies may impact the Company's overall operations either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable the Company to purchase all of the Company's supply needs at market prices without a material disruption of operations if supplies are interrupted from any of the Company's existing sources. Although no assurances can be given that supplies of propane will be readily available in the future, the Company expects a sufficient supply to continue to be available.
F-127
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
Accounts Receivable
Accounts receivable are reported net of the allowance for doubtful accounts. Allowance for doubtful accounts are based on specific identification and historical collection results and have generally been within management's expectations. Account balances are charged against the allowance when it is anticipated that the receivable will not be collected. The balance is considered past due or delinquent based on contractual terms with the customer.
Allowance for doubtful accounts comprise of the following:
| |
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Accounts Receivable |
$ | 5,915,364 | $ | 3,471,372 | |||
Less: allowance for doubtful accounts |
(115,680 | ) | (180,021 | ) | |||
Total, net |
$ | 5,799,684 | $ | 3,291,351 | |||
The activity in the allowance for doubtful accounts consisted of the following:
| |
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Balance, beginning of the year |
$ | 180,021 | $ | 161,817 | |||
Accounts receivable written off, net of recoveries |
(74,312 | ) | (190,478 | ) | |||
Provision for loss on accounts receivable |
9,971 | 208,682 | |||||
Balance, end of the year |
$ | 115,680 | $ | 180,021 | |||
Customer deposits and advances
We offer certain of our customer's prepayment programs which require customers to pay a fixed periodic amount or to otherwise prepay a portion of their anticipated propane purchases. Customer prepayments, in excess of associated billings, are classified as customer deposits and advances on the Balance Sheets.
Advertising
The Company's policy is to expense advertising costs as they are incurred. The amount charged to advertising expense was $54,841 in 2012 and $210,149 in 2011 and is included in operating expenses.
Delivery Expenses
Expenses associated with the delivery of products to customers (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating expenses on the Statements of Operations.
Operating expenses
Operating expenses primarily includes the personnel, vehicle, delivery, advertising, office, credit and collections and other expenses related to the distribution of products and related equipment and supplies.
F-128
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
General and administrative expenses
General and administrative expenses primarily include wages and benefits and department related costs for human resources, finance and accounting, administrative support and supply.
Leases
The Company has operating leases. Minimum rent payments under operating leases are recognized as an expense on a straight-line basis over the lease term, including any rent free periods.
Revenue Recognition
Revenues from the sale of propane are recognized in the period that services are provided or products are delivered. Revenues from the sale of parts and equipment are recognized at the latter of sale or installation. We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis.
Asset retirement obligation
Asset retirement obligations include legal or contractual obligations associated with the retirement of tangible long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. We record liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made. Management was not able to reasonably measure the fair value of asset retirement obligations as of June 6, 2012 and December 31, 2011 because settlement dates were indeterminable.
Construction in progress
Construction-in-progress is stated at cost and not depreciated until placed in service and transferred to property, plant and equipment.
Property, Plant and Equipment and Related Depreciation
Property, plant, and equipment are recorded at cost less accumulated depreciation. Maintenance and repairs are charged to operating expenses and any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. Depreciation is recorded on a straight-line basis over the estimated useful life of the asset.
Goodwill and Other Intangible Assets
We apply ASC 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill and intangible assets. In accordance with these standards, we amortize all finite lived intangible assets over their respective estimated weighted average useful lives, while goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets not subject to amortization are tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test for impairment at the reporting unit level. Estimation of future economic benefit requires management to make assumptions about numerous variables including selling
F-129
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
prices, costs, the level of activity and appropriate discount rates. If it is determined that the fair value of a reporting unit is below its carrying amount, our goodwill or intangible assets with indefinite lives will be impaired at that time.
The Company performs its annual impairment review of goodwill and indefinite lives intangible assets on December 31 or when a triggering event occurs between annual impairment tests. No impairment loss was recorded in 2012 or 2011.
We test long-lived asset groups for impairment when events or circumstances indicate that the net book value of the asset group may not be recoverable. We test an asset group for impairment by estimating the undiscounted cash flows expected to result from its use and eventual disposition. If the estimated undiscounted cash flows are lower than the net book value of the asset group, we then estimate the fair value of the asset group and record a reduction to the net book value of the assets and a corresponding impairment loss.
Business Combinations
The Company uses the acquisition method of accounting in accordance with ASC 805, "Business Combinations". The acquisition method of accounting requires the Company to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and to refine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for a business combination may be adjusted). Each acquired company's operating results are included in the Company's financial statements starting from the date of acquisition. The purchase price is the equivalent of fair value of consideration transferred. Tangible and identifiable intangible assets generally are comprised of customer lists, trade names and non-compete agreements. Goodwill is recognized for the excess of the purchase price over the net fair value of assets acquired and liabilities assumed.
Costs that are incurred to complete the business combination such as banking, legal and other professional fees are not considered part of the consideration transferred and are charged to operating expenses as they are incurred. See note 6.
Inventories
Inventories are stated at the lower of cost or market. The cost of propane inventories is determined using the weighted average cost of propane delivered to customer service locations and includes any storage fees and in-bound freight costs.
Impairment of Long-Lived Assets
Long-lived assets such as property, plant and equipment, and purchased intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value.
F-130
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
2. Summary of Significant Accounting Policies (Continued)
Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3).
Fair value Measurement
Fair value is defined as the price that the Company would receive to sell an asset or pay to transfer a liability (an exit price) in an orderly transaction between market participants on the measurement date. In determining fair value, U.S. GAAP establishes a three-level hierarchy used in measuring fair value, as follows:
- •
- Level 1 inputs are quoted prices available for identical assets and liabilities in active markets;
- •
- Level 2 inputs are observable for the asset or liability, either directly or indirectly, including quoted prices
for similar assets and liabilities in active markets or other inputs that are observable or can be corroborated by observable market data;
- •
- Level 3 inputs are less observable and reflect our own assumptions.
Fair value of Financial Instruments
The Company's financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and commodity derivatives. The carrying value of the Company's trade and other receivables, accounts payable and accrued expenses approximates fair value due to their short term maturity. The carrying amount reported for long-term debt approximates fair value because the underlying instruments are at rates similar to current rates offered to the Company for debt with the same remaining maturities. Price risk management assets and liabilities are recorded at fair value.
Income Taxes
The Company is a tax pass through entity, and, therefore, is generally not subject to income taxes. The Company follows the guidance for uncertainties in income taxes and did not identify or record any uncertain tax positions not meeting the more likely than not standard as of June 6, 2012 or December 31, 2011. The Company records interest related to unrecognized tax benefits in interest expense and penalties in operating expenses.
3. Supplemental Cash flow Information
| |
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Cash paid for interest |
$ | 599 | $ | 13,535 | |||
Non-cash financing activities
|
June 6, 2012 | December 31, 2011 | |||||
|---|---|---|---|---|---|---|---|
Long term debt assumed and non-compete agreement notes payable issued in acquisitions |
$ | — | $ | 591,623 | |||
Net advances to parent |
$ | (509,364 | ) | $ | — | ||
F-131
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
4. Inventories
Propane inventories comprise of the following at June 6, 2012 and December 31, 2011:
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Balance, December 31, 2011 and June 6, 2012 |
$ | 2,419,737 | $ | 3,381,778 | |||
5. Property, Plant and Equipment, net
Property, plant, and equipment comprise of the following at June 6, 2012 and December 31, 2011:
| |
Estimated Useful Life |
2012 | 2011 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
Land |
— | $ | 2,217,607 | $ | 2,217,607 | |||||
Buildings and improvements |
10 - 40 years | 4,258,066 | 4,212,812 | |||||||
Machinery and equipment |
10 years | 1,857,033 | 1,830,938 | |||||||
Customer tanks, regulators & tank sets |
10 - 30 years | 16,151,041 | 14,234,456 | |||||||
Dispensers and bulk storage |
5 - 30 years | 21,810,431 | 21,144,904 | |||||||
Motor vehicles |
3 - 20 years | 8,153,528 | 8,124,951 | |||||||
Office furniture and equipment |
3 - 10 years | 363,223 | 363,223 | |||||||
Construction in progress |
— | 4,259,076 | 2,141,906 | |||||||
Gross property, plant and equipment |
59,070,005 | 54,270,797 | ||||||||
Less accumulated depreciation |
(15,238,988 | ) | (13,497,074 | ) | ||||||
Property, plant and equipment, net |
$ | 43,831,017 | $ | 40,773,723 | ||||||
Depreciation expense totaled $2,003,242 for 2012 and $4,835,889 for 2011, which is included in depreciation and amortization expense in the Statements of Operations.
Construction in progress at June 6, 2012 and December 31, 2011 consists primarily of cages and cage set labor and a production facility and will be classified as dispensers and bulk storage and buildings and improvements, respectively, within property, plant and equipment when completed.
6. Acquisitions
On April 4, 2011, the Company acquired substantially all of the retail propane distribution assets of Plantation Propane, Inc. ("Plantation") for $752,282 in cash.
On July 13, 2011, the Company acquired all of the retail propane distribution assets of Fitzgerald Distributing, LLC Kiss the Cook Propane for $76,188 in cash.
On August 25, 2011, the Company acquired substantially all of the retail propane distribution assets of Gas Incorporated for $2,878,572 in cash.
On September 20, 2011, the Company acquired substantially all of the retail propane distribution assets of Horizon Propane Cylinders, LLC ("Horizon") for a total consideration of $3,385,697 in cash.
F-132
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
6. Acquisitions (Continued)
The following table represents the preliminary allocation of the aggregated purchase price to the fair value of assets acquired and liabilities assumed related to the four acquisitions described above:
Accounts receivable |
$ | 189,813 | ||
Inventories |
192,290 | |||
Property, plant and equipment |
4,778,100 | |||
Customer lists (15 years) |
1,956,258 | |||
Non-compete agreements (5 - 10 years) |
137,913 | |||
Non-amortizable intangible assets—Trade names |
91,728 | |||
Goodwill |
650,074 | |||
Total assets |
7,996,176 | |||
Less liabilities assumed |
(613,598 | ) | ||
Less bargain purchase gain |
(289,839 | ) | ||
Total |
$ | 7,092,739 | ||
With the exception of Plantation, the above table represents a preliminary allocation for each entity acquired. The Company finalizes allocations within one year of the acquisition date. The goodwill amounts noted for all 2011 acquisitions reflect the difference between purchase prices less the fair value of net assets acquired. Goodwill was warranted because these acquisitions enhance the Company's current operations and certain acquisitions are expected to reduce costs through synergies with existing operations. The Company expects all of the goodwill acquired to be tax deductible. The Company does not believe that the acquired intangible assets have any significant residual value at the end of their respective useful life.
The results of operations of the acquisitions are included in the Company's Statements of Operations since their acquisition date.
The bargain purchase gain noted for the Horizon acquisition of $268,096 and for the Plantation acquisition for $21,743 reflects the difference between the purchase price less the fair value of the net assets acquired and has been recognized within general and administrative expenses within the Statements of Operations. As there was bargain purchase the acquirer reassessed whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reassessed the value of the assets. It was determined that the bargain purchase gain was the result of a negotiated reduced price.
The following table summarizes the detail of the acquired intangible assets during 2011:
| |
Combined fair value | Weighted-average useful lives |
|||
|---|---|---|---|---|---|
Customer lists |
$ | 1,956,258 | 15 years | ||
Non-compete agreements |
137,913 | 8 years | |||
Trade names |
91,728 | Indefinite | |||
Total Identifiable Intangible assets |
$ | 2,185,899 | |||
F-133
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
7. Goodwill and Intangible Assets
The goodwill and intangible assets comprise of the following at June 6, 2012 and December 31, 2011:
Goodwill
|
|
|||
|---|---|---|---|---|
Balance, January 1, 2011 |
$ | 2,969,178 | ||
Acquisitions |
650,074 | |||
Balance, December 31, 2011 and June 6, 2012 |
$ | 3,619,252 | ||
Intangible assets
|
Estimated Useful Life |
June 6, 2012 | December 31, 2011 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
Customer lists |
15 years | $ | 5,132,389 | $ | 5,132,389 | |||||
Non-compete agreements |
5 - 10 years | 742,283 | 742,283 | |||||||
Non-amortizable intangible assets—Trade names |
— | 1,566,145 | 1,566,145 | |||||||
Gross intangible assets |
7,440,817 | 7,440,817 | ||||||||
Less accumulated amortization |
(1,400,630 | ) | (1,219,126 | ) | ||||||
Total intangible assets, net |
$ | 6,040,187 | $ | 6,221,691 | ||||||
Amortization expense totaled $181,504 for 2012 and $336,071 for 2011, which is included in depreciation and amortization expense in the Statements of Operations.
Estimated amortization expense of intangible assets during the next five fiscal years is as follows:
Remainder of 2012 |
$ | 237,352 | ||
2013 |
418,856 | |||
2014 |
418,389 | |||
2015 |
418,056 | |||
2016 |
407,912 | |||
Thereafter |
2,573,477 | |||
Total |
$ | 4,474,042 | ||
8. Accrued Liabilities
Other accrued liabilities are comprised of the following at June 6, 2012 and December 31, 2011:
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Wages and employee benefits |
$ | 2,308,463 | $ | 426,272 | |||
Business insurance reserves |
3,329,946 | 3,738,520 | |||||
Income taxes |
54,852 | 39,403 | |||||
Other |
90,866 | 77,854 | |||||
Total accrued liabilities |
$ | 5,784,127 | $ | 4,282,049 | |||
F-134
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
9. Long-Term Liabilities
Other long-term liabilities are comprised of the following at June 6, 2012 and December 31, 2011:
| |
2012 | 2011 | |||||
|---|---|---|---|---|---|---|---|
Non-compete debt with imputed interest at rates averaging 3.512% |
$ | 614,849 | $ | 614,849 | |||
Price risk management liabilities (Note 10) |
434,834 | — | |||||
Total long-term liabilities |
1,049,683 | 614,849 | |||||
Less current portion: |
(174,205 | ) | (174,205 | ) | |||
Long-term liabilities |
$ | 875,478 | $ | 440,644 | |||
The non-compete debt relates to the acquisitions. The payments are scheduled to be paid over the next 5 years as detailed below:
Remainder of 2012 |
$ | 174,205 | ||
2013 |
104,524 | |||
2014 |
108,196 | |||
2015 |
111,995 | |||
2016 |
115,929 | |||
Thereafter |
— | |||
Total |
$ | 614,849 | ||
10. Derivative Instruments
Policies: The Company established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit, and interest rates. Management is responsible for the overall management of these risks, including monitoring exposure limits. Management receives regular briefings on exposures and overall risk management in the context of market activities.
Commodity Price Risk: The Company's business is exposed to market risks related to the volatility of propane prices. The Company uses forward physical contracts to manage its purchasing exposure to market fluctuations in propane prices.
At June 6, 2012, the Company had outstanding contracts with total nominal amounts for 3,887,200 gallons maturing through November 2013.
F-135
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
10. Derivative Instruments (Continued)
The following table summarizes the fair value of our financial assets and liabilities consisting of only commodity derivatives measured and recorded at the fair value on a recurring basis as of June 6, 2012 based on inputs used to derive their fair values:
Description
|
Total fair value June 6, 2012 |
Fair Value Measurements using in active markets for identical assets and liabilities (Level 1) |
Fair value measurements using other observable inputs (Level 2) |
Fair market measurements using unobservable inputs (Level 3) |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Assets |
|||||||||||||
Commodity derivatives |
$ | — | $ | — | $ | — | $ | — | |||||
Liabilities |
|||||||||||||
Commodity derivatives |
2,198,963 | — | 2,198,963 | — | |||||||||
Total liabilities |
$ | 2,198,963 | $ | — | $ | 2,198,963 | $ | — | |||||
The Company valued its propane commodity derivatives using the New York Mercantile Exchange ("NYMEX").
Credit Risk: The Company's business is exposed to credit risk. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Company attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a guarantee from a parent company with potentially better credit.
The Company's Balance Sheet as of June 6, 2012 was impacted by derivative instruments activities as detailed below:
Mark-to-market derivatives
|
Location of the fair value of the derivatives on the balance sheet |
Amount of fair value recognized on derivatives |
||||
|---|---|---|---|---|---|---|
Price risk management liabilities |
Short term liabilities | $ | 1,764,129 | |||
Price risk management liabilities |
Long-term liabilities | 434,834 | ||||
During the period from January 1, 2012 to June 6, 2012, total loss on commodity derivatives was $3,052,223 and was recorded in cost of sales.
In 2011, HPX did not enter into any derivative contracts. In 2011, the Company was allocated by HOLP a portion of derivative gains and losses on certain contracts which were entered into on their behalf amounting to a total gain of $1,063,814 included in cost of sales. At January 1, 2012, the derivative financial instruments were legally assigned and contributed at fair value to HPX at a fair value liability of $539,990.
Accounting for derivatives
All derivatives are recognized in the Balance Sheets as either an asset or a liability measured at fair value.
F-136
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
10. Derivative Instruments (Continued)
The Company has not applied hedge accounting to any derivative contracts. Cash flows from derivatives are reported as cash flows from operating activities in the same category as the cash flows from the items being managed.
11. Parent's Equity in Division
HOLP and ETP use a centralized approach to cash management. Inter-company accounts represent the net result of the Company's participation in such cash management and treasury programs. Inter-company accounts are also credited and charged for allocations of certain corporate costs. The balances of the inter-company accounts are classified in parent's equity in division. There are no terms of settlement or interest charges associated with this balance.
The Statements of Operations include expenses allocated by HOLP in 2011 to cover human resources, information technology, tax, insurance, accounting, legal, treasury services and other corporate services provided to the Company. These allocations were based on the most relevant allocation method to services provided primarily based on payroll and revenues that management believes are reasonable and result in an allocation of the Company's cost of doing business. Amounts allocated from HOLP to the Company in 2011 were $2,332,315. On January 1, 2012, the TSA took effect and AmeriGas continued to support the operations of HPX. Upon the sale of HPX to JP Energy Partners LP the buyer had an option to continue with the TSA for a year after completion of the sale.
12. Retirement Plan
Employees were eligible to participate in ETP's 401k savings plan which included a match. The matching contributions were calculated using a formula based on employee contributions. The 401k match for 2011 and 2012 was $131,424 and $92,687, respectively, and was included within operating expenses on the Statements of Operations.
13. Income Taxes
The Company recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Company has evaluated tax positions taken or expected to be taken in the course of preparing the Company's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Tax expense of $15,450 and $37,066 for 2012 and 2011, respectively, related to state income taxes.
F-137
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
14. Commitments and Contingencies
Legal Matters
The Company may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, the Company is sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. The Company maintains liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent and which are generally accepted in the industry. However there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
The Company is party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, the Company evaluates the merits of the case, the exposure to the matter, possibly legal or settlement strategies, the likelihood of unfavorable outcome and the availability of insurance coverage. If the Company determines that an unfavorable outcome of a particular matter is probable and can be estimated, the Company accrues the contingent obligation as well as any expected insurance recoverable amounts related to the contingency. As of June 6, 2012 and December 31, 2011, the Company had accruals of $3,329,946 and $3,738,520 respectively, reflected in accrued liabilities on the Balance Sheets related to these contingent obligations. The Company had insurance recovery assets in prepaids and other current assets of $2,958,618 and $3,417,062 as of June 6, 2012 and December 31, 2011, respectively. As new information becomes available, the estimates may change. The impact of these changes may have a significant effect on results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, the Company may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
No amounts have been recorded in the June 6, 2012 and December 31, 2011 Balance Sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.
Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Company's activities. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
F-138
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
14. Commitments and Contingencies (Continued)
The Company accounts for environmental contingencies in accordance with the ASC 410, "Asset Retirements and Environmental Obligations" related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At June 6, 2012 and December 31, 2011, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Operating Leases
The Company leases equipment under non-cancellable operating leases. The Company's aggregate rental expense was $133,001 at 2012 and $326,938 for 2011. Minimum future payments under non-cancelable operating leases as of June 6, 2012 are as follows:
Remainder of 2012 |
$ | 146,542 | ||
2013 |
197,108 | |||
2014 |
81,703 | |||
2015 |
14,723 | |||
Thereafter |
— | |||
Total |
$ | 440,076 | ||
15. Related Parties
Transactions with these related parties for 2012 and 2011 are outlined below:
| |
|
Amount | |||||||
|---|---|---|---|---|---|---|---|---|---|
Related Party
|
Type of Transaction | 2012 | 2011 | ||||||
Enterprise |
Purchase of propane | $ | — | $ | 2,089,199 | ||||
AmeriGas |
Corporate services | 284,736 | — | ||||||
In 2011, Enterprise supplied a portion of the Company's propane purchases. Enterprise was considered to be a related party to the Company due to Enterprises ownership of outstanding common units of Energy Transfer Equity, L.P. ("ETE") which is a related party to ETP.
In January 2012, Enterprise sold a significant portion of its ownership in ETE common units. Subsequent to that transaction, Enterprise owns less than 5% of ETE's outstanding common units and was no longer considered a related party.
In 2012, ETP held a substantial interest in AmeriGas, which ETP received as part of the consideration for the sale of HOLP to AmeriGas. AmeriGas provided HPX with certain services including human resources, information technology, tax, insurance, legal and treasury services within the TSA in 2012 at a cost of $284,736 which was included within the general and administrative expenses in the Statement of Operations in 2012.
F-139
Heritage Propane Express, LLC
Notes to Financial Statements (Continued)
15. Related Parties (Continued)
At June 6, 2012 and December 31, 2011, the Company had an accounts receivable balance of $44,071 and $0, respectively, from HOLP relating to a payment from an HPX customer deposited into a HOLP bank account. The funds were repaid after the balance sheet period.
The above related party transactions were consummated on terms equivalent to those that prevail in arm's length transactions.
16. Subsequent Events
The Company has performed an evaluation of subsequent events through May 18, 2013 which is the date the financial statements were available to be issued.
The Company was acquired by JP Energy Partners LP on June 7, 2012.
F-140
To
the Board of Directors of
JP Energy Partners LP
We have audited the accompanying financial statements of the Crude Oil Supply and Logistics Business of Parnon Gathering Inc. (the Business), which comprise the statements of revenues and direct operating expenses for the seven months ended July 31, 2012, and the year ended December 31, 2011, and the related notes to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal controls relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility
Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates used by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the statements, and are not intended to be a complete presentation of the Business' results of operations.
Opinion
In our opinion, the statements of revenues and direct operating expenses present fairly, in all material respects, the revenues and direct operating expenses of the Crude Oil Supply and Logistics Business of Parnon Gathering Inc. for the seven months ended July 31, 2012 and the year ended December 31, 2011, in accordance with accounting principles generally accepted in the United States of America.
/s/
Travis Wolff, LLP
Dallas, Texas
May 7, 2014
F-141
The Crude Oil Supply and Logistics Business of Parnon Gathering Inc.
Statements of Revenues and Direct Operating Expenses
Seven Months Ended July 31, 2012
and the Year Ended December 31, 2011
| |
Notes | Seven Months Ended 7/31/2012 |
Year Ended 12/31/2011 |
||||||
|---|---|---|---|---|---|---|---|---|---|
Revenues: |
|||||||||
Crude oil revenue from third parties |
3 | $ | 38,339,796 | $ | 67,709,280 | ||||
Crude oil revenue from a related party |
3,5 | 180,327,906 | 304,408,894 | ||||||
| | | | | | | | | | |
Total operating revenues |
218,667,702 | 372,118,174 | |||||||
| | | | | | | | | | |
Direct Operating Expenses: |
|||||||||
Cost of products sold |
4 | 206,576,825 | 355,174,000 | ||||||
Operating expenses |
4 | 9,345,805 | 12,817,484 | ||||||
Depreciation and amortization |
4 | 1,295,295 | 1,497,590 | ||||||
| | | | | | | | | | |
Total direct operating expenses |
217,217,925 | 369,489,074 | |||||||
| | | | | | | | | | |
Excess of revenues over direct operating expenses |
$ | 1,449,777 | $ | 2,629,100 | |||||
| | | | | | | | | | |
| | | | | | | | | | |
See accompanying notes to financial statements.
F-142
The Crude Oil Supply and Logistics Business of Parnon Gathering Inc.
Notes to Statements of Revenues and Direct Operating Expenses
Note 1—Basis of Presentation
Parnon Gathering Inc., (the Company) a Delaware corporation, was formed on September 8, 2009, and commenced operations on October 9, 2009. As a wholly owned subsidiary of Parnon Holdings Inc., Parnon Gathering Inc. was formed to provide midstream gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil (see Note 3). Effective August 3, 2012, pursuant to an equity purchase agreement between JP Energy Development LP (the Purchaser), JP Energy Development GP LLC (the General Partner), and Parnon Holdings Inc. (the Seller), Parnon Gathering Inc. was acquired by JP Energy Development LP and subsequently converted into Parnon Gathering LLC. The operations of Parnon Gathering Inc. consisted of a pipeline business and a crude oil supply and logistics business. In February 2014, JP Energy Partners LP (JPE Energy Partners), an affiliate entity of JP Energy Development LP, acquired the assets associated with the Crude Oil Supply and Logistics Business of Parnon Gathering LLC (the Business) from JP Energy Development LP.
The accompanying statements of revenues and direct operating expenses of the Business acquired by JP Energy Partners (the Statements) were prepared by the Company based on carved-out financial information and data from the Company's historical accounting records. Because the crude oil supply and logistics business acquired is not a separate legal entity from the rest of the Company, the accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America (GAAP) in that they do not reflect certain expenses that were incurred in connection with the ownership and operation of the Company including, but not limited to, interest expense, the provision for income taxes, general and administrative expenses, and other indirect expenses. These costs were not separately allocated to the crude oil supply and logistics business in the accounting records of the Company (Note 6). Furthermore, balance sheets and statements of cash flows required by GAAP are not presented as such information is not readily available for the crude oil supply and logistics business because not all of the historical cost and related working capital balances are segregated or easily obtainable. Accordingly, the accompanying statements are presented in lieu of the financial statements required under Rule 3-01, Rule 3-02 and Rule 3-05 of Securities and Exchange Commission Regulation S-X. The financial statements presented are not indicative of the financial condition or results of operations of the acquired Business going forward due to the omission of the above mentioned expenses.
Note 2—Use of Estimates
The preparation of the statements of revenues and direct operating expenses in conformity with GAAP requires the Company's management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of the Statements.
Note 3—Revenue Recognition
The Business purchases and gathers crude oil from producers for transmission and sale to refiners, common carrier pipelines, or to terminals and storage facilities. Revenue is recognized when 1) persuasive evidence of an arrangement exists, 2) services have been rendered or the physical product has been delivered, 3) the sales price is fixed and determinable and 4) collectability is reasonably assured.
F-143
The Crude Oil Supply and Logistics Business of Parnon Gathering Inc.
Notes to Statements of Revenues and Direct Operating Expenses (Continued)
Note 3—Revenue Recognition (Continued)
The Business uses short-term transportation and delivery contracts that designate the desired product grade, price, quantity, and delivery point which are generally renewable month-to-month unless cancelled. Fees charged under these arrangements are either contractual or regulated by governmental agencies, including the Federal Energy Regulatory Commission (FERC). Customers will notify the Business of the leases that need to be gathered during the delivery month and payment is billed and due the following month. The price charged is generally based on an average index price in effect during the delivery month and is market-based, but it also may include pricing differentials for such factors as delivery location and product grade.
Note 4—Direct Operating Expenses
Cost of products sold
Cost of products sold represents costs incurred to purchase crude oil as a part of our short-term transportation and delivery contracts.
Operating expenses
Operating expenses consist of transportation and pipeline fees, field personnel salaries, consultancy and professional fees, and other operating expenses directly incurred in generating revenues. Certain costs such as interest expense, income tax expense and general and administrative expenses were not allocated to the crude oil supply and logistics business.
Depreciation & amortization
The Business records depreciation expense related to property and equipment on a straight-line basis over the estimated useful lives of its assets. For the seven months ended July 31, 2012 and the year ended December 31, 2011, the Business recognized $1,116,122 and $1,190,436 of depreciation expense, respectively.
The Business has a customer list intangible asset related to an acquisition in 2010. The Business records amortization expense for this intangible asset over its estimated useful life. For the seven months ended July 31, 2012 and the year ended December 31, 2011, the Business recognized $179,173 and $307,154 of amortization expense, respectively.
Note 5—Related Party
The Business sells crude oil to Parnon Energy Inc. (Parnon Energy), a subsidiary of Parnon Holdings Inc. Sales to Parnon Energy are included in crude oil revenues from a related party in the accompanying statements. For the seven months ended July 31, 2012 and the year ended December 31, 2011, the Business recognized revenues from Parnon Energy of $180,327,906 and $304,408,894, respectively.
F-144
The Crude Oil Supply and Logistics Business of Parnon Gathering Inc.
Notes to Statements of Revenues and Direct Operating Expenses (Continued)
Note 6—Unallocated costs (unaudited)
The following table contains unaudited data showing certain expenses incurred in connection with the ownership and operation of the Company that have not been allocated to the crude oil supply and logistics business:
| |
Seven Months Ended 7/31/2012 |
Year Ended 12/31/2011 |
|||||
|---|---|---|---|---|---|---|---|
| |
(unaudited) |
(unaudited) |
|||||
Corporate compensation |
$ | 924,202 | $ | 2,129,800 | |||
General and administrative expense |
300,282 | 412,061 | |||||
Interest expense |
793,873 | 619,083 | |||||
Income tax expense (benefit) |
(493,560 | ) | 49,614 | ||||
| | | | | | | | |
Total expenses not allocated to the Business |
$ | 1,524,797 | $ | 3,210,558 | |||
| | | | | | | | |
| | | | | | | | |
F-145
To
the Shareholder of
Parnon Storage Inc.
We have audited the accompanying balance sheets of Parnon Storage Inc. (the Company) (wholly-owned by Parnon Holdings Inc.), as of March 31, 2011 and 2012, and the related statements of income, shareholder's equity and cash flows for each of the years in the three-year period ended March 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As disclosed in Note 1, effective August 1, 2012 the Company was purchased by JP Energy Partners LP, a Delaware limited partnership. The purchase transferred all of the equity interests of the Company to the buyer.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Parnon Storage Inc. as of March 31, 2011 and 2012, and the results of its operations and cash flows for each of the years in the three-year period ended March 31, 2012 in conformity with accounting principles generally accepted in the United States of America.
/s/ Travis Wolff, LLP
Dallas,
Texas
April 2, 2013
F-146
PARNON STORAGE INC.
BALANCE SHEETS
| |
March 31, 2011 |
March 31, 2012 |
|||||
|---|---|---|---|---|---|---|---|
ASSETS |
|||||||
Current assets |
|||||||
Cash and cash equivalents |
$ | 32,150 | $ | 80,595 | |||
Restricted cash equivalents |
3,138,183 | 2,538,974 | |||||
Due from Parnon Energy Inc. |
36,756 | — | |||||
Prepaid expenses |
552,042 | 484,984 | |||||
Deferred tax asset |
457,253 | 434,404 | |||||
| | | | | | | | |
Total current assets |
4,216,384 | 3,538,957 | |||||
| | | | | | | | |
Non-current assets |
|||||||
Restricted cash equivalents |
2,800,000 | 2,800,000 | |||||
Property, plant and equipment, net |
62,857,004 | 61,202,234 | |||||
Deferred financing costs, net |
235,156 | 169,531 | |||||
Other assets |
175,667 | 44,410 | |||||
| | | | | | | | |
Total non-current assets |
66,067,827 | 64,216,175 | |||||
| | | | | | | | |
Total Assets |
$ | 70,284,211 | $ | 67,755,132 | |||
| | | | | | | | |
| | | | | | | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
|||||||
Current liabilities |
|||||||
Accounts payable and accrued expenses |
$ | 184,270 | $ | 218,681 | |||
Due to Parnon Gathering Inc. |
2,578 | 2,936 | |||||
Due to Parnon Holdings Inc. |
13,136,277 | 4,790,470 | |||||
Due to Parnon Energy Inc. |
— | 800 | |||||
Current maturities of term note payable |
5,000,000 | 5,000,000 | |||||
Fair value of interest rate swap |
1,825,388 | 1,662,590 | |||||
Income taxes payable to Parnon Holdings Inc. |
2,183,317 | 4,737,767 | |||||
Income taxes payable |
— | 20,000 | |||||
| | | | | | | | |
Total current liabilities |
22,331,830 | 16,433,244 | |||||
Non-current liabilities |
|||||||
Deferred tax liabilities |
1,985,185 | 3,416,022 | |||||
Term note payable, less current maturities |
34,318,828 | 29,318,828 | |||||
Fair value of interest rate swap |
2,166,540 | 2,622,765 | |||||
| | | | | | | | |
Total Liabilities |
60,802,383 | 51,790,859 | |||||
| | | | | | | | |
Shareholder's Equity |
|||||||
Share capital, no par value, 200 shares authorized |
1 | 1 | |||||
Retained earnings |
9,481,827 | 15,964,272 | |||||
| | | | | | | | |
Total shareholder's equity |
9,481,828 | 15,964,273 | |||||
| | | | | | | | |
Total Liabilities and Shareholder's Equity |
$ | 70,284,211 | $ | 67,755,132 | |||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to financial statements
F-147
PARNON STORAGE INC.
STATEMENTS OF INCOME
| |
Year ended March 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2010 | 2011 | 2012 | |||||||
REVENUES |
||||||||||
Storage revenue from Parnon Energy Inc. |
$ | 16,777,027 | $ | 18,433,015 | $ | 18,583,019 | ||||
| | | | | | | | | | | |
Total revenues |
16,777,027 | 18,433,015 | 18,583,019 | |||||||
| | | | | | | | | | | |
OPERATING EXPENSES |
||||||||||
Storage tank fees |
1,631,834 | 1,873,015 | 2,023,019 | |||||||
Selling, general, and administrative |
865,647 | 983,544 | 1,005,366 | |||||||
Depreciation |
1,507,056 | 1,649,221 | 1,657,153 | |||||||
| | | | | | | | | | | |
Total costs and expenses |
4,004,537 | 4,505,780 | 4,685,538 | |||||||
| | | | | | | | | | | |
INCOME FROM OPERATIONS |
12,772,490 | 13,927,235 | 13,897,481 | |||||||
OTHER INCOME (EXPENSE) |
||||||||||
Interest expense—third parties |
(3,247,416 | ) | (3,110,094 | ) | (2,834,337 | ) | ||||
Interest expense—Parnon Holdings Inc. |
(599,471 | ) | (476,869 | ) | (239,060 | ) | ||||
Unrealized loss on interest rate swap |
1,720,649 | (78,929 | ) | (293,427 | ) | |||||
Other income |
7,383 | 26 | 25 | |||||||
| | | | | | | | | | | |
INCOME BEFORE INCOME TAXES |
10,653,635 | 10,261,369 | 10,530,682 | |||||||
Income tax expense |
(1,852,680 |
) |
(3,998,216 |
) |
(4,048,237 |
) |
||||
| | | | | | | | | | | |
NET INCOME |
$ | 8,800,955 | $ | 6,263,153 | $ | 6,482,445 | ||||
| | | | | | | | | | | |
| | | | | | | | | | | |
See accompanying notes to financial statements
F-148
PARNON STORAGE INC.
STATEMENTS OF SHAREHOLDER'S EQUITY
| |
Share Capital | |
|
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Retained Earnings (Accumulated Deficit) |
|
|||||||||||
| |
Shares | Amount | Total | ||||||||||
Balance—March 31, 2009 |
1 | $ | 1 | $ | (5,582,281 | ) | $ | (5,582,280 | ) | ||||
Net Income |
— |
— |
8,800,955 |
8,800,955 |
|||||||||
| | | | | | | | | | | | | | |
Balance—March 31, 2010 |
1 | 1 | 3,218,674 | 3,218,675 | |||||||||
| | | | | | | | | | | | | | |
Net Income |
— | — | 6,263,153 | 6,263,153 | |||||||||
| | | | | | | | | | | | | | |
Balance—March 31, 2011 |
1 | 1 | 9,481,827 | 9,481,828 | |||||||||
| | | | | | | | | | | | | | |
Net Income |
— | — | 6,482,445 | 6,482,445 | |||||||||
Balance—March 31, 2012 |
1 | $ | 1 | 15,964,272 | $ | 15,964,273 | |||||||
| | | | | | | | | | | | | | |
See accompanying notes to financial statements
F-149
PARNON STORAGE INC.
STATEMENTS OF CASH FLOWS
| |
Year ended March 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| |
2010 | 2011 | 2012 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||
Net income |
$ | 8,800,955 | $ | 6,263,153 | $ | 6,482,445 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||
Depreciation |
1,507,056 | 1,649,221 | 1,657,153 | |||||||
Amortization of deferred financing fees |
49,219 | 65,625 | 65,625 | |||||||
Unrealized loss (gain) on interest rate swap |
(1,720,649 | ) | 78,929 | 293,427 | ||||||
Deferred income taxes |
(1,029,142 | ) | 2,557,074 | 1,453,686 | ||||||
Fees on long-term debt |
32,349 | — | — | |||||||
Paid in-kind interest on long-term debt |
842,672 | — | — | |||||||
Changes in operating assets and liabilities: |
||||||||||
Prepaid expenses |
(602,426 | ) | 50,384 | 67,058 | ||||||
Other assets |
(90,863 | ) | (84,804 | ) | 131,257 | |||||
Accounts payable and accrued expenses |
210,588 | (75,128 | ) | 34,411 | ||||||
Due to/from related parties |
723,290 | (71,563 | ) | 37,914 | ||||||
Income taxes payable |
3,108,447 | (925,130 | ) | 2,574,450 | ||||||
| | | | | | | | | | | |
NET CASH PROVIDED BY OPERATING ACTIVITIES |
11,831,496 | 9,507,761 | 12,797,426 | |||||||
| | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||
Purchase of property, plant, and equipment |
(11,323,992 | ) | (551,860 | ) | (2,383 | ) | ||||
| | | | | | | | | | | |
NET CASH USED IN INVESTING ACTIVITIES |
(11,323,992 | ) | (551,860 | ) | (2,383 | ) | ||||
| | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||
Restricted cash equivalents |
(4,883,491 | ) | 3,862,309 | 599,209 | ||||||
Borrowings on term note—related party |
— | 2,842,701 | 237,688 | |||||||
Repayments of term note—related party |
— | (11,199,747 | ) | (8,583,495 | ) | |||||
Borrowings on term note |
6,196,973 | — | — | |||||||
Repayments of term note |
(1,250,000 | ) | (5,000,000 | ) | (5,000,000 | ) | ||||
| | | | | | | | | | | |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
63,482 | (9,494,737 | ) | (12,746,598 | ) | |||||
| | | | | | | | | | | |
Net change in cash and cash equivalents |
570,986 | (538,836 | ) | 48,445 | ||||||
Cash and cash equivalents, beginning of period |
— | 570,986 | 32,150 | |||||||
| | | | | | | | | | | |
Cash and cash equivalents, end of period |
$ | 570,986 | $ | 32,150 | $ | 80,595 | ||||
| | | | | | | | | | | |
| | | | | | | | | | | |
SUPPLEMENTAL DISCLOSURES: |
||||||||||
Cash paid for state income taxes |
$ | — | $ | 2,218,293 | $ | 20,100 | ||||
Cash paid for interest |
263,780 | 4,274,908 | 3,119,415 | |||||||
Non-cash investing and financing transactions: |
||||||||||
Financing fees paid with long-term debt |
$ | 350,000 | $ | — | $ | — | ||||
See accompanying notes to financial statements
F-150
PARNON STORAGE INC.
Notes to Financial Statements
March 31, 2012, 2011 and 2010
Note 1—Organization and Summary of Significant Accounting Policies
Organization and nature of business
In May 2007, Parnon Storage LLC was organized under the laws of the State of Oklahoma and later converted to Parnon Storage Inc. (the Company) in July 2007. The Company owns five storage tanks capable of holding up to 3,000,000 barrels of crude oil located in Cushing, Oklahoma, the hub terminal of West Texas Intermediate (WTI). A third party operator is located onsite at the Cushing terminal and manages the Company's daily activities which currently consist of taking physical possession of crude oil that is under derivative contracts entered into by Parnon Energy Inc., an affiliate due to common ownership. The Company's primary place of business is 1437 S. Boulder Ave., Suite #1070, Tulsa, Oklahoma, 74119 USA and its registered address is 115 SW 89th Street, Oklahoma City, OK 73139 USA.
The Company is a wholly-owned subsidiary of Parnon Holdings Inc. (PHI), a domestic energy holding company with no substantive operations, which consolidates the accounts of the Company along with three other related wholly-owned subsidiaries, Parnon Energy Inc. (PEI), Parnon Gathering Inc. (PGI), and Arcadia Fuels Inc. (AFI). Farahead Holdings Limited (Farahead), a foreign entity organized under the laws of the Republic of Cyprus, ultimately owns and controls PHI and other foreign entities in the energy industry (collectively, the Group).
Subsequent events
Effective August 1, 2012 the Company was purchased by JP Energy Partners LP, a Delaware limited partnership. The purchase transferred all of the equity interests of the Company to the buyer.
Management of the Company has evaluated subsequent events through the date the financial statements were available to be issued.
Revenue recognition
The Company recognizes revenue when 1) persuasive evidence of an arrangement exists, 2) services have been rendered or the physical product has been delivered, 3) the sales price is fixed and determinable and 4) collectability is reasonably assured. The Company currently earns monthly storage fees under a long-term contract with PEI based on a fixed rate per barrel and receives payment based on the maximum committed space whether or not it is fully utilized in a given month.
Cash equivalents and restricted cash equivalents
The Company considers all highly liquid investments with an original or remaining maturity of three months or less at the date of purchase to be cash equivalents. At March 31, 2011 and 2012, the Company had $5,938,183 and $5,338,974, respectively, held in money market accounts which are used as collateral and restricted for use under the terms of the facility and related collateral agreement with a major financial institution (See Note 4). These accounts are shown as restricted cash equivalents on the balance sheets.
F-151
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
Property, plant, and equipment
The Company capitalizes expenditures for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives have been extended; and all land, regardless of cost. The Company records property, plant, and equipment at its cost, which is depreciated on a straight-line basis over its estimated useful life. The determination of the useful lives requires management to consider the age (in the case of acquired assets), manufacturing specifications, technological advances, and historical data. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand. The estimated useful lives of property, plant, and equipment currently range from 4 to 40 years. The Company did not record any impairment in 2010, 2011 or 2012.
Deferred financing costs
Costs related to obtaining and executing debt agreements are capitalized and amortized to interest expense on a straight-line basis, which approximates the interest method, over the term of the related debt. Costs incurred in connection with the financing of the acquisition of the Company were approximately $350,000. The loan origination fees will be amortized over the life of the commitment.
Amortization of deferred financing costs charged to interest expense for the years ended March 31, 2010, 2011, and 2012, totalled $49,219, $65,625 and $65,625, respectively. Accumulated amortization as of March 31, 2011 and 2012 was $114,844 and $180,469, respectively. Estimated amortization of deferred financing costs for each of the next two years is $65,625 and $38,281 for year three.
Asset retirements and environmental obligations
The Company did not record any obligation for March 31, 2011 and 2012. The fair value of an asset retirement liability is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. The Company did not deem any liability reasonably estimable for the years ended March 31, 2011 and 2012.
Income taxes
Deferred taxes are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Valuation allowances are provided if based upon the weight of available evidence, it is more likely than not that some or all of the deferred tax assets will be realized.
At March 31, 2011 and 2012, no uncertain tax positions have been identified and the Company is no longer subject to tax examinations by tax authorities for years prior to March 31, 2009. If applicable, interest and penalties related to uncertain tax positions will be recognized in income tax expense. No amounts were recognized during the years ended March 31, 2010, 2011 and 2012.
F-152
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
Interest rate swap
The Company uses interest rate swaps to reduce the exposure to market fluctuations by converting variable interest rates to fixed interest rates for borrowings under the facility agreement.
The Company recognizes and measures the swaps at fair value on the balance sheets. In hedging its interest rate risk, the Company determined that the interest rate swaps do not meet the criteria for specific hedge accounting; therefore changes in the fair value are included in earnings.
The fair value of the interest rate swap was obtained using a present value model as if the agreement was terminated at December 31, 2011 and 2012. This amount represents the estimated amount that the Company would receive or pay to terminate the agreement.
Fair value measurements
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. US GAAP also establishes a fair value hierarchy, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. US GAAP describes three levels of inputs that may be used to measure fair value:
Level 1: Unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2: Observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the investment.
Concentrations of risk
The Company's activities expose it to a variety of financial risks which include market, credit, and liquidity risks.
Farahead monitors the financial risks of the Company and takes necessary measures to minimize them. The Company's overall risk management program focuses on the unpredictability of financial
F-153
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
markets and seeks to minimize potential adverse effects on the Company's financial performance. The Company has exposure to the following significant financial risks described below:
Market Risk
The Company is currently responsible for storing crude oil purchased by PEI and receives a fixed fee according to a long-term agreement. The Company is therefore dependent upon the success or failure of PEI's trading activities and its ability to continue as a going concern. Based on the nature and demand for energy, the Company believes that there are several alternatives or other options available and that the business strategy can be revised accordingly should PEI encounter any future difficulties.
Interest Rate Risk
Cash flow interest rate risk is the risk that future cash flows of a financial instrument will fluctuate because of changes in market interest rates. Fair value interest rate risk is the risk that the value of a financial instrument will fluctuate due to changes in market interest rates.
The Company has borrowings under third party and related party facilities which could make it susceptible to losses from unexpected increases in interest rates. The Company attempts to mitigate this risk through the use of an interest rate swap (See Note 3).
Credit Risk
Credit risk arises from the possibility that customers may not be able to settle obligations within the normal terms of transactions.
At March 31, 2011 and 2012, the Company had concentrations of credit risk for its cash and cash equivalents held by financial institutions. The Company's cash in U.S. bank deposit accounts at times may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.
The Company currently earns all revenue from PEI; however, the storage tanks can be used by third party customers as considered necessary, so the source of potential revenue is not limited.
Liquidity Risk
Liquidity risk is the risk that the Company will encounter difficulty in raising funds or the capital necessary to meet commitments and obligations as they become due. Liquidity risk may result from an inability to sell financial assets quickly at close to fair value.
The Company has long-term debt due to a third party financial institution and also to PHI for the construction of its storage tanks (See Note 4). Additionally, nearly all of the Company's working capital and income is currently from services provided to PEI. The Company believes it will be able to obtain additional related party loans from its Parent or other subsidiaries within the consolidated group if needed to meet its financial obligations and continue as a going concern.
F-154
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Significant estimates include, but are not limited to, the fair value of the interest rate swap; useful lives assigned to property, plant, and equipment for depreciation; asset retirement obligations; and valuation of deferred taxes. Actual results could differ from those estimates.
Note 2—Property, Plant, and Equipment
The following is a summary of the Company's property and equipment at March 31:
| |
2011 | 2012 | |||||
|---|---|---|---|---|---|---|---|
Storage facility |
$ | 66,013,596 | $ | 66,013,596 | |||
Computer equipment |
8,384 | 10,767 | |||||
Furniture and fixtures |
24,694 | 24,694 | |||||
| | | | | | | | |
Total property, plant and equipment |
66,046,674 | 66,049,057 | |||||
Less: accumulated depreciation |
3,189,670 | 4,846,823 | |||||
| | | | | | | | |
Property, plant and equipment, net |
$ | 62,857,004 | $ | 61,202,234 | |||
| | | | | | | | |
| | | | | | | | |
Depreciation expense for property and equipment totaled $1,507,056, $1,649,221 and $1,657,153 for the years ended March 31, 2010, 2011 and 2012, respectively. Substantially all assets are pledged as collateral on the Company's facility agreement (See Note 4).
Note 3—Interest Rate Swap
The Company classifies changes in the fair value of its interest rate swap separately on the statements of income while monthly settlements are included in interest expense. The change in the fair value was $1,720,649, ($78,929) and ($293,427) and total monthly settlements paid were $2,146,502, $2,055,798 and $1,892,045 for the years ended March 31, 2010, 2011 and 2012, respectively. The Company's interest rate swap fixes the interest rate at 4.33% per annum through the termination date, May 31, 2015. The notional amount ranges from $43,875,000 at March 31, 2012 to $29,250,000 at maturity. The Company has classified its interest rate swap as a Level 2 instrument in the fair value hierarchy.
Note 4—Term note payable
On January 30, 2008, the Company entered into a facility agreement with a consortium of reputable lenders for a total commitment of $54,000,000 to finance the acquisition, construction and initial operation of the Company's five crude oil storage tanks. On October 30, 2009, outstanding borrowings of $45,568,828 were converted into a term note maturing October 30, 2014 with interest at the three-month LIBOR plus 2.0% (2.56% at March 31, 2012) and payments due quarterly. The underlying assets (including required insurance) and the restricted cash equivalents serve as collateral,
F-155
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 4—Term note payable (Continued)
and Farahead Holdings Limited and Farahead Investments Inc. are guarantors. The facility agreement contains various financial and other covenants which the Company must comply with on a quarterly and annual basis, notably to maintain a minimum actual and projected debt service coverage ratio. The Company was in compliance with these covenants as of March 31, 2011 and 2012.
Effective May 31, 2008, the Company entered into an interest rate swap agreement with the primary lender as required under the facility agreement. The Company is paying interest at a fixed rate of 4.33% and is receiving variable interest at one month LIBOR (0.244% at March 31, 2012). The calculation of interest is based on specified variable monthly notional amounts which do not exceed $54,000,000. At March 31, 2011 and 2012, the notional amount of the swap was $47,250,000 and $43,875,000, respectively.
Future maturities of the term note payable are as follows at March 31, 2012:
Years Ending March 31,
|
Amount | |||
|---|---|---|---|---|
2013 |
$ | 5,000,000 | ||
2014 |
5,000,000 | |||
2015 |
24,318,828 | |||
| | | | | |
Total |
$ | 34,318,828 | ||
| | | | | |
| | | | | |
Note 5—Taxation
The composition of income taxes consisted of the following for the years ended March 31:
| |
2010 | 2011 | 2012 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
Current tax expense |
||||||||||
State |
$ | 23,375 | $ | 680,431 | $ | 445,828 | ||||
Federal |
2,858,447 | 760,711 | 2,148,723 | |||||||
| | | | | | | | | | | |
|
2,881,822 | 1,441,142 | 2,594,551 | |||||||
Deferred tax expense |
||||||||||
State |
$ | 17,209 | $ | 66,683 | $ | 72,476 | ||||
Federal |
(1,046,351 | ) | 2,490,391 | 1,381,210 | ||||||
| | | | | | | | | | | |
|
(1,029,142 | ) | 2,557,074 | 1,453,686 | ||||||
| | | | | | | | | | | |
|
$ | 1,852,680 | $ | 3,998,216 | $ | 4,048,237 | ||||
| | | | | | | | | | | |
| | | | | | | | | | | |
F-156
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 5—Taxation (Continued)
The reconciliation of statutory tax on the pre-tax income and tax expense follows:
| |
2010 | 2011 | 2012 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
Tax at U.S. statutory rate |
$ | 3,622,236 | $ | 3,591,479 | $ | 3,685,739 | ||||
Additional tax (tax savings) in respect of: |
||||||||||
State tax net of Federal benefit |
32,637 | 485,624 | 362,264 | |||||||
Non-deductible expenses |
32,511 | 34,015 | 234 | |||||||
Change in tax rates |
— | 137,098 | — | |||||||
Change in valuation allowance |
(1,834,704 | ) | — | — | ||||||
Taxes in respect of previous years |
— | (250,000 | ) | — | ||||||
| | | | | | | | | | | |
|
$ | 1,852,680 | $ | 3,998,216 | $ | 4,048,237 | ||||
| | | | | | | | | | | |
| | | | | | | | | | | |
Deferred tax assets and liabilities are comprised of the following at March 31:
| |
2011 | 2012 | |||||
|---|---|---|---|---|---|---|---|
Deferred tax assets: |
|||||||
Financial instruments |
$ | 1,478,346 | $ | 1,582,888 | |||
Deferred tax liabilities: |
|||||||
Property, plant, and equipment |
(2,787,527 | ) | (4,384,797 | ) | |||
Prepaid assets |
(206,464 | ) | (179,709 | ) | |||
Other |
(12,287 | ) | — | ||||
| | | | | | | | |
|
$ | (1,527,932 | ) | $ | (2,981,618 | ) | |
| | | | | | | | |
| | | | | | | | |
The net amount of deferred income taxes expected to be settled in more than 12 months is $4,384,797.
The Company is included in the consolidated tax return filed by PHI. Income tax expense (benefit) in the Company's statement of operations has been allocated based upon the Company's share of taxable income or loss included in the consolidated return. At March 31, 2011 and 2012, respectively, $2,183,317 and $4,737,767 was due to PHI for income taxes.
Note 6—Related Party Transactions
On January 1, 2008, the Company entered into a $20,000,000 revolving credit facility with PHI for general corporate and working capital purposes, which is subordinated to the Company's term note. The outstanding balance was $13,136,277 and $4,790,470 (including accrued interest of $87,723 and $41,705) at March 31, 2011 and 2012. There is no scheduled maturity or fixed payment terms. Interest accrues quarterly at the three-month LIBOR plus 2.5% (3.0557% at March 31, 2012) and is added to the outstanding balance. For the year ended March 31, 2012, no draws were taken and principal payments made were $8,298,417. Interest of $285,078 was paid during 2012.
As described in Note 6, substantially all of the Company's revenues come from PEI. Additionally, the Company has a current amount due to PGI of $2,936 and a current amount due to PEI of $800.
F-157
PARNON STORAGE INC.
Notes to Financial Statements (Continued)
March 31, 2012, 2011 and 2010
Note 7—Commitments and Contingencies
Legal and regulatory proceedings
The Company may be subject to various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings may be covered, in whole or in part, by insurance. The Company is also directly or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for potential expansion projects. These events, individually and in the aggregate, are not expected to have a material adverse effect on the financial statements.
On May 24, 2011, the U.S. Commodity Futures Trading Commission ("CFTC") issued a complaint against two traders and three group companies (namely PEI, Arcadia Energy (Suisse) SA, and Arcadia Petroleum Limited), alleging an unlawful manipulation scheme to artificially increase the price of physical and manipulate the NYMEX WTI financial contract oil price. The group companies deny the allegations and the matter will be adjudicated in court.
It is the intention of the group companies to seek an application to dismiss the CFTC complaint. No provision has been made as of March 31, 2012 for any liability arising as a result of the allegations.
Operating leases
On August 2, 2007, the Company entered into a lease with a third party operator for the land beneath the storage tanks in Cushing, Oklahoma, prior to their construction. The initial lease term is 50 years with consecutive renewal option periods of 5 years each thereafter (up to an additional 30 years) if the Company gives proper notice. The Company is responsible for maintaining insurance, paying taxes, general maintenance and repairs, and complying with relevant laws and regulations. The Company must return the land, including any improvements, to the third party operator upon expiration or termination of the lease. The Company pays fixed monthly lease payments which are scheduled to increase gradually over time. The Company incurred approximately $122,000 for the year ended March 31, 2010 and $120,000 in rent expense for the years ended March 31, 2011 and 2012. Future minimum lease payments required under this non-cancelable operating lease as of March 31, 2012 is as follows:
Years Ending March 31,
|
Amount | |||
|---|---|---|---|---|
2013 |
$ | 120,000 | ||
2014 |
120,000 | |||
2015 |
120,000 | |||
2016 |
120,000 | |||
2017 |
120,000 | |||
Thereafter |
6,045,438 | |||
| | | | | |
Total |
$ | 6,645,438 | ||
| | | | | |
| | | | | |
Operating Agreement
On January 30, 2008, the Company entered into an agreement with a third party operator to provide certain services for the storage tanks in Cushing, Oklahoma, for the remaining term of the land lease. The Company pays a monthly base service fee which is determined based on a formula using the number of tanks in service and may incur other costs for additional services. The Company incurred $1,631,834, $1,873,015 and $2,023,019 in service fees for the years ended March 31, 2010, 2011 and 2012, respectively.
F-158
PARNON STORAGE INC.
Income Statements
| |
For the Three Months Ended June 30, | ||||||
|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | |||||
| |
(Unaudited) |
||||||
Revenue: |
|||||||
Storage revenue from Parnon Energy Inc. |
$ | 4,614,338 | $ | 4,656,601 | |||
Operating expenses: |
|||||||
Storage tank fees |
474,338 | 516,601 | |||||
Selling, general, and administrative |
215,453 | 246,742 | |||||
Depreciation |
414,239 | 414,358 | |||||
| | | | | | | | |
|
1,104,030 | 1,177,701 | |||||
| | | | | | | | |
Income from operations |
3,510,308 | 3,478,900 | |||||
Other income (expense): |
|||||||
Interest expense—third parties |
(238,944 | ) | (228,023 | ) | |||
Interest expense—Parnon Holdings Inc. |
(79,449 | ) | (25,698 | ) | |||
Realized/unrealized loss on interest rate swap |
(884,070 | ) | (207,189 | ) | |||
Other income (expense) |
(147 | ) | (147 | ) | |||
| | | | | | | | |
|
(1,202,610 | ) | (461,057 | ) | |||
| | | | | | | | |
Income before provision for income taxes |
2,307,698 | 3,017,843 | |||||
Income tax expense |
(923,257 | ) | (1,207,358 | ) | |||
| | | | | | | | |
Net income |
$ | 1,384,441 | $ | 1,810,485 | |||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to financial statements.
F-159
PARNON STORAGE INC.
Statements of Shareholder's Equity
| |
Share Capital | |
|
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |
Shares | Amount | Retained Earnings | Total | |||||||||
Balance at March 31, 2012 |
1 | $ | 1 | $ | 15,964,272 | $ | 15,964,273 | ||||||
Net income (unaudited) |
— | — | 1,810,485 | 1,810,485 | |||||||||
| | | | | | | | | | | | | | |
Balance at June 30, 2012 (Unaudited) |
1 | $ | 1 | $ | 17,774,757 | $ | 17,774,758 | ||||||
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
See accompanying notes to financial statements.
F-160
PARNON STORAGE INC.
Statements of Cash Flows
| |
For the Three Months Ended June 30, | ||||||
|---|---|---|---|---|---|---|---|
| |
2011 | 2012 | |||||
| |
(Unaudited) |
||||||
Cash flows from operating activities: |
|||||||
Net income |
$ | 1,384,441 | $ | 1,810,485 | |||
Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||
Depreciation |
414,239 | 414,358 | |||||
Amortization of deferred financing fees |
16,407 | 16,407 | |||||
Unrealized (gain) loss on interest rate swap |
392,636 | (234,830 | ) | ||||
Deferred income taxes |
— | — | |||||
Changes in operating assets and liabilities: |
|||||||
Prepaid expenses |
72,508 | 126,529 | |||||
Other assets |
54,252 | 5,793 | |||||
Accounts payable and accrued expenses |
(20,024 | ) | 13,548 | ||||
Due to/from related parties |
46,748 | (1,328 | ) | ||||
Income taxes payable |
903,157 | 1,207,358 | |||||
| | | | | | | | |
Net cash provided by operating activities |
3,264,364 | 3,358,320 | |||||
| | | | | | | | |
Cash flows from investing activities: |
|||||||
Purchase of property, plant, and equipment |
— | — | |||||
| | | | | | | | |
Net cash provided by (used in) investing activities |
— | — | |||||
Cash flows from financing activities: |
|||||||
Decrease (increase) in restricted cash equivalents |
656,146 | (128,988 | ) | ||||
Borrowings on term note—related party |
79,448 | 25,698 | |||||
Repayments of term note—related party |
(2,735,036 | ) | (1,987,853 | ) | |||
Repayments of term note |
(1,250,000 | ) | (1,250,000 | ) | |||
| | | | | | | | |
Net cash used in financing activities |
(3,249,442 | ) | (3,341,143 | ) | |||
| | | | | | | | |
Increase (decrease) in cash and cash equivalents |
14,922 | 17,177 | |||||
Cash and cash equivalents, beginning of period |
32,150 | 80,595 | |||||
| | | | | | | | |
Cash and cash equivalents, end of period |
$ | 47,072 | $ | 97,772 | |||
| | | | | | | | |
| | | | | | | | |
Supplemental cash flow information: |
|||||||
Cash paid for income taxes |
$ | — | $ | — | |||
| | | | | | | | |
| | | | | | | | |
Cash paid for interest expense |
$ | 798,654 | $ | 701,993 | |||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to financial statements.
F-161
PARNON STORAGE INC.
Notes to Interim Financial Statements
(Unaudited)
Note 1—Organization and Summary of Significant Accounting Policies
Organization and nature of business
In May 2007, Parnon Storage LLC was organized under the laws of the State of Oklahoma and later converted to Parnon Storage Inc. (the Company) in July 2007. The Company owns five storage tanks capable of holding up to 3,000,000 barrels of crude oil located in Cushing, Oklahoma, the marketing hub of West Texas Intermediate (WTI). A third party operator is located onsite at the Cushing terminal and manages the Company's daily activities, which currently consist of taking physical possession of crude oil that is under derivative contracts entered into by Parnon Energy Inc., an affiliate due to common ownership. The Company's primary place of business is 1437 S. Boulder Ave., Suite #1070, Tulsa, Oklahoma, 74119 USA and its registered address is 115 SW 89th Street, Oklahoma City, OK 73139 USA.
The Company is a wholly-owned subsidiary of Parnon Holdings Inc. (PHI), a domestic energy holding company with no substantive operations, which consolidates the accounts of the Company along with three other related wholly- owned subsidiaries, Parnon Energy Inc. (PEI), Parnon Gathering Inc. (PGI), and Arcadia Fuels Inc. (AFI). Farahead Holdings Limited (Farahead), a foreign entity organized under the laws of the Republic of Cyprus, ultimately owns and controls PHI and other foreign entities in the energy industry (collectively, the Group).
Subsequent events
Effective August 1, 2012 the Company was purchased by JP Energy Partners LP, a Delaware limited partnership (JP Energy). The purchase transferred all of the equity interests of the Company to JP Energy.
Basis of presentation
The interim financial statements are unaudited but reflect, in management's opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair statement of financial position and the results of the Company's operations for the three months ended June 30, 2011 and 2012. The interim financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended March 31, 2012.
Interim results are not necessarily indicative of results for the full fiscal year.
Revenue recognition
The Company recognizes revenue when 1) persuasive evidence of an arrangement exists, 2) services have been rendered or the physical product has been delivered, 3) the sales price is fixed and determinable and 4) collectability is reasonably assured. The Company currently earns monthly storage fees under a long-term contract with PEI based on a fixed rate per barrel and receives payment based on the maximum committed space whether or not it is fully utilized in a given month.
F-162
PARNON STORAGE INC.
Notes to Interim Financial Statements (Continued)
(Unaudited)
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
Property and equipment
The Company capitalizes expenditures for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives have been extended; and all land, regardless of cost. The Company records property, plant, and equipment at its cost, which is depreciated on a straight-line basis over its estimated useful life. The determination of the useful lives requires management to consider the age (in the case of acquired assets), manufacturing specifications, technological advances, and historical data. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand. The estimated useful lives of property, plant, and equipment currently range from 4 to 40 years.
Deferred financing costs
Costs related to obtaining and executing debt agreements are capitalized and amortized to interest expense on a straight-line basis, which approximates the interest method, over the term of the related debt. The loan origination fees will be amortized over the life of the commitment.
Amortization of deferred financing costs charged to operations for the three month periods ended June 30, 2011 and 2012, totaled $16,407 for each period. Accumulated amortization as of June 30, 2012 was $197,056.
Fair value measurements
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. US GAAP also establishes a fair value hierarchy, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. US GAAP describes three levels of inputs that may be used to measure fair value:
Level 1: Unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2: Observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the investment.
F-163
PARNON STORAGE INC.
Notes to Interim Financial Statements (Continued)
(Unaudited)
Note 1—Organization and Summary of Significant Accounting Policies (Continued)
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Significant estimates include, but are not limited to, the fair value of the interest rate swap; useful lives assigned to property, plant, and equipment for depreciation; asset retirement obligations; and valuation of deferred taxes. Actual results could differ from those estimates.
Note 2—Interest Rate Swap
The Company combines changes in the fair value of its interest rate swap (unrealized gains/losses) on the income statements with monthly settlements (realized gains/losses). The change in the fair value was ($392,636) and $234,830 and total monthly settlements paid were $491,434 and $442,019 for the three month periods ended June 30, 2011 and 2012, respectively. The Company's interest rate swap fixes the interest rate at 4.33% per annum through the termination date, May 31, 2015. The Company has classified its interest rate swap as a Level 2 instrument in the fair value hierarchy.
Note 3—Term Note Payable
On January 30, 2008, the Company entered into a facility agreement with a consortium of reputable lenders for a total commitment of $54,000,000 to finance the acquisition, construction and initial operation of the Company's five crude oil storage tanks. On October 30, 2009, outstanding borrowings of $45,568,828 were converted into a term note maturing October 30, 2014 with interest at the three-month LIBOR plus 2.0% and payments due quarterly. The underlying assets (including required insurance) and the restricted cash equivalents serve as collateral, and Farahead Holdings Limited and Farahead Investments Inc. are guarantors. The facility agreement contains various financial and other covenants which the Company must comply with on a quarterly and annual basis, notably to maintain a minimum actual and projected debt service coverage ratio.
Effective May 31, 2008, the Company entered into an interest rate swap agreement with the primary lender as required under the facility agreement. The Company is paying interest at a fixed rate of 4.33% and is receiving variable interest at one month LIBOR. The calculation of interest is based on specified variable monthly notional amounts which do not exceed $54,000,000.
Note 4—Related Party Transactions
On January 1, 2008, the Company entered into a $20,000,000 revolving credit facility with PHI for general corporate and working capital purposes, which is subordinated to the Company's term note. The outstanding balance was $2,828,315 (including accrued interest of $25,698) at June 30, 2012. For the three month period ended June 30, 2012, no draws were taken and principal payments made were $1,947,520. Interest of $87,723 and $40,334 was paid during the three month period ended June 30, 2011 and 2012, respectively. There is no scheduled maturity or fixed payment terms. Interest accrues quarterly at the three-month LIBOR plus 2.5% and is added to the outstanding balance.
F-164
PARNON STORAGE INC.
Notes to Interim Financial Statements (Continued)
(Unaudited)
Note 4—Related Party Transactions (Continued)
All of the Company's revenues come from PEI. Additionally, at June 30, 2012, the Company had a balance due to PGI of $2,408.
Note 5—Commitments and Contingencies
Legal and regulatory proceedings
The Company may be subject to various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings may be covered, in whole or in part, by insurance. The Company is also directly or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for potential expansion projects. These events, individually and in the aggregate, are not expected to have a material adverse effect on the financial statements.
Operating agreement
On January 30, 2008, the Company entered into an agreement with a third party operator to provide certain services for the storage tanks in Cushing, Oklahoma, for the remaining term of the land lease. The Company pays a monthly base service fee which is determined based on a formula using the number of tanks in service and may incur other costs for additional services. The Company incurred $474,338 and $516,601 in service fees for the three month periods ended June 30, 2011 and 2012, respectively.
F-165
To
the Board of Directors
Wildcat Permian Services, LLC
Dallas, Texas
Report on the Financial Statement
We have audited the accompanying statements of operations and cash flows of Wildcat Permian Services, LLC (the "Company") for the period from January 1, 2013 through October 6, 2013 and for the period from September 12, 2012 (inception) through December 31, 2012, and the related notes to the financial statements.
Management's Responsibility for the Financial Statement
Management is responsible for the preparation and fair presentation of these statements of operations and cash flows in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the financial statement that is free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on the statements of operations based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of operations are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statement. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statement in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statement.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the statements of operations and cash flows referred to above present fairly, in all material respects, the results of operations of Wildcat Permian Services, LLC for the period from January 1, 2013 through October 6, 2013 and for the period from September 12, 2012 (inception) through December 31, 2012, in accordance with accounting principles generally accepted in the United States of America.
/s/ Hein & Associates LLP
Dallas,
Texas
May 7, 2014
F-166
WILDCAT PERMIAN SERVICES, LLC
STATEMENTS OF OPERATIONS
| |
FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH OCTOBER 6, 2013 |
FOR THE PERIOD FROM SEPTEMBER 12, 2012 (INCEPTION) THROUGH DECEMBER 31, 2012 |
|||||
|---|---|---|---|---|---|---|---|
REVENUES |
$ | 2,968,084 | $ | — | |||
OPERATING COSTS AND EXPENSES: |
|||||||
Direct operating expenses |
1,071,221 | 82,868 | |||||
General and administrative |
573,066 | 129,950 | |||||
Depreciation |
1,033,028 | 2,786 | |||||
| | | | | | | | |
Total operating expenses |
2,677,316 | 215,604 | |||||
INCOME (LOSS) BEFORE INCOME TAXES |
290,769 |
(215,604 |
) |
||||
| | | | | | | | |
INCOME TAX EXPENSE |
19,075 | — | |||||
| | | | | | | | |
NET INCOME (LOSS) |
$ | 271,694 | $ | (215,604 | ) | ||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to these financial statements.
F-167
WILDCAT PERMIAN SERVICES, LLC
STATEMENTS OF CASH FLOWS
| |
FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH OCTOBER 6 2013 |
FOR THE PERIOD FROM SEPTEMBER 12, 2012 (INCEPTION) THROUGH DECEMBER 31, 2012 |
|||||
|---|---|---|---|---|---|---|---|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|||||||
Net loss |
$ | 271,694 | $ | (215,604 | ) | ||
Adjustments to reconcile net loss to net cash used in operating activities: |
|||||||
Depreciation |
1,033,028 | 2,786 | |||||
Changes in operating assets and liabilities: |
|||||||
Accounts receivable |
(99,821 | ) | — | ||||
Prepaid expenses |
23,937 | (51,862 | ) | ||||
Inventory |
(283,637 | ) | — | ||||
Accounts payable |
43,483 | 130,902 | |||||
| | | | | | | | |
Net cash provided by (used in) operating activities |
988,684 | (133,778 | ) | ||||
CASH FLOWS FROM INVESTING ACTIVITIES— |
|||||||
Additions to pipeline and equipment |
(20,793,917 | ) | (11,859,042 | ) | |||
| | | | | | | | |
Net cash used in investing activities |
(20,793,917 | ) | (11,859,042 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES— |
|||||||
Capital contributions |
16,559,000 | 17,809,000 | |||||
| | | | | | | | |
Net cash provided by financing activities |
16,559,000 | 17,809,000 | |||||
NET CHANGE IN CASH AND CASH EQUIVALENTS |
(3,246,233 |
) |
5,816,180 |
||||
CASH AND CASH EQUIVALENTS, beginning of period |
5,816,180 |
— |
|||||
| | | | | | | | |
CASH AND CASH EQUIVALENTS, end of period |
$ | 2,569,948 | $ | 5,816,180 | |||
| | | | | | | | |
| | | | | | | | |
NON-CASH CAPITAL CONTRIBUTIONS OF PIPELINE AND EQUIPMENT |
$ | — | $ | 2,191,000 | |||
| | | | | | | | |
| | | | | | | | |
See accompanying notes to these financial statements.
F-168
WILDCAT PERMIAN SERVICES, LLC
NOTES TO FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
Wildcat Permian Services, LLC (the "Company"), a Texas limited liability company, was established on September 12, 2012 to acquire, own, maintain, develop, and sell midstream assets. The Company is currently primarily engaged in the purchase, sale, and transport of crude oil in Crockett, Reagan, Irion, Schleicher, and Upton Counties in West Texas.
As of December 31, 2012, the Company had not yet generated revenue from its planned principal business operations and was thus considered to be in the development stage. The Company completed the construction of the pipeline and commenced operations during the first quarter of 2013 and exited the development stage.
The Company is a limited liability company ("LLC"). As an LLC, the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC and, unless otherwise noted, the individual member's liability for indebtedness of an LLC is limited to the member's actual capital contribution.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Pipeline and Equipment
Pipeline and equipment are recorded at cost less accumulated depreciation. Depreciation expense is provided using the straight-line method, which, in the opinion of management, is adequate to allocate the costs of these assets over the estimated useful lives as follows:
Pipelines and equipment |
14 years | |
Computer equipment and vehicles |
3 - 5 years |
Depreciation expense for the period from January 1, 2013 through October 6, 2013 and September 12, 2012 (inception) through December 31, 2012 was $1,033,028 and $2,786, respectively.
Expenditures for maintenance and repairs are expensed as incurred. Costs of major replacements and improvements are capitalized. When property is retired or otherwise disposed of, the cost and accumulated depreciation are removed from appropriate accounts and any gain or loss is included in income.
The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may be impaired. Based upon this evaluation, no impairment expense was indicated period from January 1, 2013 through October 6, 2013 and September 12, 2012 (inception) through December 31, 2012.
Linefill
Pipelines generally require a minimum volume of product in the system to enable the system to operate. Such product, known as linefill, is generally not available to be withdrawn from the system. Linefill owned by the Company is recorded at historical cost, is included in property, plant and equipment in the balance sheet, and is not depreciated.
Revenue
The Company earns revenues from transportation and marketing fees from certain fixed-margin transactions related to the Company's crude oil pipeline system in west Texas. The fixed-margin
F-169
WILDCAT PERMIAN SERVICES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
transactions are structured such that the Company purchases crude oil from a producer or supplier at a designated receipt point at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking a fixed margin that is, in effect, economically equivalent to a transportation fee. Sales of product are recognized at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. Any transportation costs the Company incurs to ship product on third-party infrastructure are included in the price of product sold to customers, and are included within product revenues and costs of products sold. The Company generally reports fixed margin-based agreements net in the statements of operations.
Income Taxes
The Company is not subject to federal income taxation because the effects of its activities accrue to the members. Accordingly, no provision for federal income taxes is included in the accompanying financial statements.
The Company remains liable for state income taxes. Income tax expense or benefit represents the current tax payable or refundable for the period, plus or minus the tax effect of the net change in the deferred tax assets and liabilities. For the period from January 1, 2013 through October 6, 2013 and September 12, 2012 (inception) through December 31, 2012 income tax expense was $19,075 and $0, respectively.
The Company is subject to certain provisions related to uncertain tax positions. The Company has reviewed its pass-through status and determined no uncertain tax positions exist and no interest or penalties have been incurred. Penalties and interest are included in income tax expense in the event they are incurred. The Company's income tax returns the periods ended 2013 and 2012 remain open for examination by the respective federal and state authorities.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting periods. Management has made certain estimates related to depreciation expense. Actual results could differ from those estimates.
Environmental
The Company may be subject to extensive environmental laws and regulations. These laws regulate the discharge of materials into the environment and maintenance of surface conditions and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. For the respective periods, the Company did not have any environmental expenditures.
3. SALE OF EQUITY INTERESTS
On October 7, 2013, Wildcat Midstream Mesquite, LLC, together with Approach Midstream Holdings LLC, the members in the Company, completed the sale of all of the equity interests of the
F-170
WILDCAT PERMIAN SERVICES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
3. SALE OF EQUITY INTERESTS (Continued)
Company to an affiliate of JP Energy Development, LP ("JP Energy") for an initial purchase price of $210,000,000, subject to certain post-closing adjustments. No adjustment for discontinued operations has been recorded in the statements of operations as this form of presentation would not provide meaningful information for the reader as all of the equity interests in the Company were sold.
In connection with the closing of the sale, the members of the Company entered into an amendment to the crude oil purchase agreement with JP Energy and Approach Midstream Holdings LLC. The amendment, among other things, amended the transportation and marketing fee equal to a flat $1.25 per barrel (aggregating the base tariff and reservation fee as a bundled fee) from the previous fee structure which called for a variable fee based upon the number of barrels shipped through the pipeline during a given period.
4. RELATED PARTY TRANSACTIONS
Wildcat Midstream Holdings, LLC ("WMH"), a member of the Company, paid for certain initial construction costs of the Company's pipeline assets as well as managing the day-to-day operations of the Company. The Company reimburses WMH on a quarterly basis for all general and administrative, payroll, construction, operations, and maintenance costs incurred on behalf of the Company. As a portion of this reimbursement, the Company pays a $33,000 monthly management fee to WMH for salary allocations of WMH employees who devote a portion of their time to the Company's operations. For the period from January 1, 2013 through October 6, 2013 and September 12, 2012 (inception) through December 31, 2012, the Company reimbursed WMH $768,631 and $492,152, respectively.
Wildcat Field Services ("Field Services") is a field services company owned by WMH that provides certain services to the Company related to the construction of its pipeline assets and equipment. For the period from January 1, 2013 through October 6, 2013, the Company had reimbursed Field Services $191,441. For the period from September 12, 2012 (inception) through December 31, 2012, the Company had reimbursed Field Services $8,305.
Approach Midstream Holdings LLC ("Approach") is a member of the Company. The Company agreed to purchase Approach's dedicated oil production from certain acreage in Crockett County for 10 years subject to certain conditions. For the period from January 1, 2013 through October 6, 2013, the Company earned transportation and marketing revenue and received fees of $1,648,994 associated with the volumes received from Approach.
5. COMMITMENTS AND CONTINGENCIES
The Company may be subject to various claims and legal proceedings covering a wide range of matters that arise in the ordinary course of its business activities, including product liability claims. Management believes that any liability that may ultimately result from the resolution of these matters will not have a material adverse effect on the results of operations of the Company.
F-171
WILDCAT PERMIAN SERVICES, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
5. COMMITMENTS AND CONTINGENCIES (Continued)
The Company has entered into certain lease transactions for a lot and trailer facilities in Barnhart, Texas. Future minimum payments under operating leases as of October 6, 2013 were as follows:
2013 |
$ | 3,570 | ||
2014 |
12,580 | |||
2015 |
9,350 | |||
| | | | | |
|
$ | 25,500 | ||
| | | | | |
| | | | | |
For the period from January 1, 2013 through October 6, 2013 and September 12, 2012 (inception) through December 31, 2012, the Company paid $20,829 and $1,683, respectively, in rent expenses related to these agreements.
6. CONCENTRATION OF CREDIT RISK
Approximately 99% of the Company's revenue for the period of January 1, 2013 through October 6, 2013 was derived from transportation and marketing fees. Substantially all of the fees were derived from two customers with whom the Company has a recurring business relationship. If any of the purchasers were lost, there are alternative purchasers with whom relationships can be established.
7. SUBSEQUENT EVENTS
The Company has evaluated subsequent events through May 7, 2014, which is the date the financial statements were available to be issued. No events or transactions have occurred subsequent to the balance sheet date other than those that have already been discussed that might require recognition or disclosure in the consolidated financial statements.
* * * * * * *
F-172
APPENDIX A
THIRD AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
JP ENERGY PARTNERS LP
A Delaware Limited Partnership
Dated
as of
[ • ], 2014
A-i
A-ii
A-iii
A-iv
THIRD AMENDED AND RESTATED AGREEMENT OF
LIMITED PARTNERSHIP OF JP ENERGY PARTNERS LP
THIS THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF JP ENERGY PARTNERS LP dated as of [ • ], 2014, is entered into by and among JP ENERGY GP II LLC, a Delaware limited liability company, as the General Partner, and the Existing Limited Partners, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:
WHEREAS, JP Energy GP LLC, a Delaware limited liability company (the "Former General Partner"), and JP Energy Holdings, LLC, a Delaware limited liability company (the "Organizational Limited Partner"), organized the Partnership as a Delaware limited partnership pursuant to an Agreement of Limited Partnership dated as of May 6, 2010 (as so amended, the "Original Agreement");
WHEREAS, the Former General Partner, the limited partners party to the Original Agreement and the Partnership amended and restated the Original Agreement by entering into the Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP, dated as of May 10, 2010 (as so amended, the "Amended and Restated Partnership Agreement");
WHEREAS, on June 27, 2011, the Former General Partner transferred all of its General Partner Interest to the General Partner, and simultaneously with such transfer the General Partner was admitted as successor General Partner in accordance with the provisions of Section 11.1 of the Amended and Restated Partnership Agreement;
WHEREAS, the General Partner, the limited partners party to the Amended and Restated Partnership Agreement and the Partnership amended and restated the Amended and Restated Partnership Agreement by entering into the Second Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP, dated as of June 27, 2011 (as so amended, the "Second Amended and Restated Partnership Agreement");
WHEREAS, the General Partner and the Existing Limited Partners desire to effect the amendment and restatement of the Second Amended and Restated Partnership Agreement on the terms set forth herein;
NOW, THEREFORE, the Second Amended and Restated Partnership Agreement is hereby amended and restated in its entirety as follows:
Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.
"Acquisition" means any transaction in which any Group Member acquires (through an asset acquisition, stock acquisition, merger or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing, over the long-term, the operating capacity or operating income of the Partnership Group from the operating capacity or operating income of the Partnership Group existing immediately prior to such transaction. For purposes of this definition, "long-term" generally refers to a period of not less than twelve months.
"Additional Book Basis" means, with respect to any Adjusted Property, the portion of any remaining Carrying Value of such Adjusted Property that is attributable to positive adjustments made to such Carrying Value determined in accordance with the provisions set forth below in this definition
A-1
of Additional Book Basis. For purposes of determining the extent to which Carrying Value constitutes Additional Book Basis:
(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event; and
(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership's Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).
"Additional Book Basis Derivative Items" means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership's Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the "Excess Additional Book Basis"), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property; provided that the provisions of the immediately preceding sentence shall apply to the determination of the Additional Book Basis Derivative Items attributable to Disposed of Adjusted Property.
"Adjusted Capital Account" means, with respect to any Partner, the balance in such Partner's Capital Account at the end of each taxable period of the Partnership after giving effect to the following adjustments: (a) credit to such Capital Account any amount which such Partner is (i) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (ii) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5) and (b) debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The "Adjusted Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.
"Adjusted Operating Surplus" means, with respect to any period, (a) Operating Surplus generated with respect to such period less (b) (i) the amount of any net increase in Working Capital Borrowings (or the Partnership's proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to such period and (ii) the amount of any net decrease in cash reserves (or the Partnership's proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and plus (c) (i) the amount of any net decrease in Working Capital Borrowings (or the Partnership's proportionate share of
A-2
any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to such period, (ii) the amount of any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above and (iii) the amount of any net increase in cash reserves (or the Partnership's proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of "Operating Surplus."
"Adjusted Property" means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(d).
"Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.
"Aggregate Quantity of IDR Reset Common Units" has the meaning given such term in Section 5.10(a).
"Aggregate Remaining Net Positive Adjustments" means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.
"Agreed Allocation" means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate in the context in which the term "Agreed Allocation" is used).
"Agreed Value" of (a) a Contributed Property means the fair market value of such property or asset at the time of contribution and (b) of an Adjusted Property means the fair market value of such Adjusted Property on the date of the Revaluation Event, in each case as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.
"Agreement" means this Third Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP, as it may be amended, supplemented or restated from time to time.
"Amended and Restated Partnership Agreement" has the meaning given such term in the Recitals.
"Associate" means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest, (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity, and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.
"Available Cash" means, with respect to any Quarter ending prior to the Liquidation Date:
(a) the sum of:
(i) all cash and cash equivalents of the Partnership Group (or the Partnership's proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter; and
A-3
(ii) if the General Partner so determines, all or any portion of additional cash and cash equivalents of the Partnership Group (or the Partnership's proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter; less
(b) the amount of any cash reserves established by the General Partner (or the Partnership's proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to:
(i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter;
(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or
(iii) provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters;
provided, however, that the General Partner may not establish cash reserves pursuant to subclause (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash within such Quarter if the General Partner so determines.
Notwithstanding the foregoing, "Available Cash" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.
"Board of Directors" means, with respect to the General Partner, its board of directors or board of managers, if the General Partner is a corporation or limited liability company, or the board of directors or board of managers of the general partner of the General Partner, if the General Partner is a limited partnership, as applicable.
"Book Basis Derivative Items" means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).
"Book-Down Event" means a Revaluation Event that gives rise to a Net Termination Loss.
"Book-Tax Disparity" means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner's share of the Partnership's Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner's Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Partner's Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.
"Book-Up Event" means a Revaluation Event that gives rise to a Net Termination Gain.
"Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.
A-4
"Capital Account" means the capital account maintained for a Partner pursuant to Section 5.4. The "Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.
"Capital Contribution" means (a) any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions) or (b) current distributions that a Partner is entitled to receive but otherwise waives.
"Capital Improvement" means (a) the construction of new capital assets by a Group Member, (b) the replacement, improvement or expansion of existing capital assets by a Group Member or (c) a capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund such Group Member's pro rata share of the cost of the construction of new, or the replacement, improvement or expansion of existing, capital assets by such Person, in each case if and to the extent such construction, replacement, improvement or expansion is made to increase, over the long-term, the operating capacity or operating income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or operating income of the Partnership Group or such Person, as the case may be, existing immediately prior to such construction, replacement, improvement, expansion or capital contribution. For purposes of this definition, "long-term" generally refers to a period of not less than twelve months.
"Capital Surplus" means Available Cash distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(a).
"Carrying Value" means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and other cost recovery deductions charged to the Partners' Capital Accounts in respect of such property and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination; provided that the Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d) to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.
"Cause" means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.
"Certificate" means a certificate, in such form (including global form if permitted by applicable rules and regulations of The Depository Trust Company and its permitted successors and assigns) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more classes of Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.
"Certificate of Limited Partnership" means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.
"Citizenship Eligible Holder" means a Limited Partner whose nationality, citizenship or other related status the General Partner determines, upon receipt of an Eligibility Certificate or other requested information, does not or would not create under any federal, state or local law or regulation to which a Group Member is subject, a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which a Group Member has an interest.
A-5
"Claim" (as used in Section 7.12(g)) has the meaning given such term in Section 7.12(g).
"Closing Date" means the first date on which Common Units are sold by the Partnership to the IPO Underwriters pursuant to the provisions of the IPO Underwriting Agreement.
"Closing Price" for any day, with respect to Limited Partner Interests of a particular class, means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the last closing bid and ask prices on such day, regular way, in either case as reported on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange, the average of the high bid and low ask prices on such day in the over-the-counter market, as reported by such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and ask prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.
"Code" means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.
"Combined Interest" has the meaning given such term in Section 11.3(a).
"Commences Commercial Service" means the date upon which a Capital Improvement is first put into or commences commercial service by a Group Member following completion of construction, replacement, improvement or expansion and testing, as applicable.
"Commission" means the United States Securities and Exchange Commission.
"Common Unit" means a Limited Partner Interest having the rights and obligations specified with respect to Common Units in this Agreement. The term "Common Unit" does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.
"Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).
"Conflicts Committee" means a committee of the Board of Directors composed of two or more directors, each of whom (a) is not an officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner (other than Group Members), (c) is not a holder of any ownership interest in the General Partner or its Affiliates or the Partnership Group other than (i) Common Units and (ii) awards that are granted to such director in his or her capacity as a director under any long-term incentive plan, equity compensation plan or similar plan implemented by the General Partner or the Partnership and (d) is determined by the Board of Directors to be independent under the independence standards for directors who serve on an audit committee of a board of directors established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading (or if no such National Securities Exchange, the New York Stock Exchange).
"Construction Debt" means debt incurred to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on other Construction Debt or (c) distributions (including incremental Incentive Distributions) on Construction Equity.
A-6
"Construction Equity" means equity issued to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on Construction Debt or (c) distributions (including incremental Incentive Distributions) on other Construction Equity. Construction Equity does not include equity issued in the Initial Public Offering.
"Construction Period" means the period beginning on the date that a Group Member enters into a binding obligation to commence a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that the Group Member abandons or disposes of such Capital Improvement.
"Contributed Property" means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property or other asset shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.
"Cumulative Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages with respect to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).
"Curative Allocation" means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).
"Current Market Price" means, as of any date for any class of Limited Partner Interests, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.
"Delaware Act" means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.
"Departing General Partner" means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.
"Derivative Partnership Interests" means any options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative securities relating to, convertible into or exchangeable for Partnership Interests.
"Disposed of Adjusted Property" has the meaning given such term in Section 6.1(d)(xii)(B).
"Economic Risk of Loss" has the meaning set forth in Treasury Regulation Section 1.752-2(a).
"Eligibility Certificate" means a certificate the General Partner may request a Limited Partner to execute as to such Limited Partner's (or such Limited Partner's beneficial owners') federal income tax status or nationality, citizenship or other related status for the purpose of determining whether such Limited Partner is an Ineligible Holder.
"Estimated Incremental Quarterly Tax Amount" has the meaning given such term in Section 6.9.
"Event Issue Value" means, with respect to any Common Unit as of any date of determination, (i) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units, or (ii) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or,
A-7
if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.
"Event of Withdrawal" has the meaning given such term in Section 11.1(a).
"Excess Additional Book Basis" has the meaning given such term in the definition of "Additional Book Basis Derivative Items."
"Excess Distribution" has the meaning given such term in Section 6.1(d)(iii)(A).
"Excess Distribution Unit" has the meaning given such term in Section 6.1(d)(iii)(A).
"Exchange Act" means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute.
"Existing Limited Partners" means the Limited Partners listed on Exhibit B to the Second Amended and Restated Partnership Agreement immediately prior to the date of this Agreement.
"Expansion Capital Expenditures" means cash expenditures for Acquisitions or Capital Improvements. Expansion Capital Expenditures shall include interest payments (including periodic net payments under related interest rate swap agreements) and related fees paid during the Construction Period on Construction Debt. Where cash expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.
"FERC" means the Federal Energy Regulatory Commission, or any successor to the powers thereof.
"Final Subordinated Units" has the meaning given such term in Section 6.1(d)(x)(A).
"First Liquidation Target Amount" has the meaning given such term in Section 6.1(c)(i)(D).
"First Target Distribution" means $0.37375 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2014, it means the product of $0.37375 multiplied by a fraction, the numerator of which is the number of days in such period and the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Sections 5.10, 6.6 and 6.9.
"Former General Partner" has the meaning given such term in the Recitals.
"Fully Diluted Weighted Average Basis" means, when calculating the number of Outstanding Units for any period, a basis that includes (a) the weighted average number of Outstanding Units during such period plus (b) all Partnership Interests and Derivative Partnership Interests (i) that are convertible into or exercisable or exchangeable for Units or for which Units are issuable, in each case that are senior to or pari passu with the Subordinated Units, (ii) whose conversion, exercise or exchange price, if any, is less than the Current Market Price on the date of such calculation, (iii) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (iv) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.6, such Partnership Interests and Derivative Partnership Interests shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided further, that if consideration will be paid to any Group Member in connection with such
A-8
conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (x) the number of Units issuable upon such conversion, exercise or exchange and (y) the number of Units that such consideration would purchase at the Current Market Price.
"General Partner" means JP Energy GP II LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).
"General Partner Interest" means the non-economic management interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it) and includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not include any rights to profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership.
"Gross Liability Value" means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm's-length transaction.
"Group" means two or more Persons that, with or through any of their respective Affiliates or Associates, have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power over or disposing of any Partnership Interests.
"Group Member" means a member of the Partnership Group.
"Group Member Agreement" means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, in each case, as such may be amended, supplemented or restated from time to time.
"Hedge Contract" means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of a Group Member to fluctuations in interest rates, the price of hydrocarbons, basis differentials or currency exchange rates in their operations or financing activities and not for speculative purposes.
"Holder" means any of the following:
(a) the General Partner who is the Record Holder of Registrable Securities;
(b) any Affiliate of the General Partner who is the Record Holder of Registrable Securities (other than natural persons who are Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates);
(c) any Person who has been the General Partner within the prior two years and who is the Record Holder of Registrable Securities;
(d) any Person who has been an Affiliate of the General Partner within the prior two years and who is the Record Holder of Registrable Securities (other than natural persons who were Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates); and
A-9
(e) a transferee and current Record Holder of Registrable Securities to whom the transferor of such Registrable Securities, who was a Holder at the time of such transfer, assigns its rights and obligations under this Agreement; provided such transferee agrees in writing to be bound by the terms of this Agreement and provides its name and address to the Partnership promptly upon such transfer.
"IDR Reset Common Units" has the meaning given such term in Section 5.10(a).
"IDR Reset Election" has the meaning given such term in Section 5.10(a).
"Incentive Distribution Right" means a Limited Partner Interest having the rights and obligations specified with respect to Incentive Distribution Rights in this Agreement (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest).
"Incentive Distributions" means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Sections 6.4(a)(v), (vi) and (vii) and 6.4(b)(iii), (iv) and (v).
"Incremental Income Taxes" has the meaning given such term in Section 6.9.
"Indemnified Persons" has the meaning given such term in Section 7.12(g).
"Indemnitee" means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of (i) any Group Member, the General Partner or any Departing General Partner or (ii) any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager, managing member, general partner, director, officer, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an "Indemnitee" for purposes of this Agreement because such Person's status, service or relationship exposes such Person to potential claims, demands, suits or proceedings relating to the Partnership Group's business and affairs.
"Ineligible Holder" means a Limited Partner who is not a Citizenship Eligible Holder or a Rate Eligible Holder.
"Initial Common Units" means the Common Units sold in the Initial Public Offering.
"Initial Limited Partners" means (a) the Existing Limited Partners; (b) the General Partner (with respect to the Incentive Distribution Rights held by it); and (c) the IPO Underwriters upon the issuance by the Partnership of Common Units as described in Section 5.2(a) in connection with the Initial Public Offering.
"Initial Public Offering" means the initial offering and sale of Common Units to the public (including the offer and sale of Common Units pursuant to the Over-Allotment Option), as described in the IPO Registration Statement.
"Initial Unit Price" means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Common Units were first offered to the public for sale as set forth on the cover page of the IPO Prospectus or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.
A-10
"Interim Capital Transactions" means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) issuances of equity interests of any Group Member (including the Common Units sold to the IPO Underwriters in the Initial Public Offering) to anyone other than the Partnership Group; (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements; and (d) capital contributions received by a Group Member.
"IPO Prospectus" means the final prospectus relating to the Initial Public Offering dated [ • ], 2014 and filed by the Partnership with the Commission pursuant to Rule 424 of the Securities Act on [ • ], 2014.
"IPO Registration Statement" means the Registration Statement on Form S-1 (File No. 333-195787), as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Public Offering.
"IPO Underwriter" means each Person named as an underwriter in Schedule I to the IPO Underwriting Agreement who purchases Common Units pursuant thereto.
"IPO Underwriting Agreement" means that certain Underwriting Agreement, dated as of [ • ], 2014, among the IPO Underwriters, the Partnership, the General Partner, JP Energy Refined Products, LLC, Pinnacle Propane, LLC and JP Energy Crude Oil Services, LLC providing for the purchase of Common Units by the IPO Underwriters.
"Liability" means any liability or obligation of any nature, whether accrued, contingent or otherwise.
"Limited Partner" means, unless the context otherwise requires, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person's capacity as a limited partner of the Partnership; provided, however, that when the term "Limited Partner" is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of any Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.
"Limited Partner Interest" means an equity interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof (but excluding Derivative Partnership Interests), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner pursuant to the terms and provisions of this Agreement; provided, however, that when the term "Limited Partner" is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of any Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.
"Liquidation Date" means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (d) of the third sentence of Section 12.1, the date on which the applicable time period during which the holders of Outstanding Units have the right to
A-11
elect to continue the business of the Partnership has expired without such an election being made and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.
"Liquidator" means one or more Persons selected pursuant to Section 12.3 to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.
"lower tier partnership" has the meaning given such term in Section 6.1(d)(xii)(D).
"Maintenance Capital Expenditure" means cash expenditures (including expenditures for the construction of new capital assets or the replacement, improvement or expansion of existing capital assets) by a Group Member made to maintain, over the long term, the operating capacity or operating income of the Partnership Group. For purposes of this definition, "long term" generally refers to a period of not less than twelve months. Where capital expenditures are made in part for Maintenance Capital Expenditures and in part for Expansion Capital Expenditures, the General Partner shall determine the allocation of the amounts paid for each.
"Merger Agreement" has the meaning given such term in Section 14.1.
"Minimum Quarterly Distribution" means $0.3250 per Unit per Quarter (or with respect to the period commencing on the Closing Date and ending on December 31, 2014, it means the product of $0.3250 multiplied by a fraction, the numerator of which is the number of days in such period and the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Sections 5.10, 6.6 and 6.9.
"National Securities Exchange" means an exchange registered with the Commission under Section 6(a) of the Exchange Act (or any successor to such Section).
"Net Agreed Value" means, (a) in the case of any Contributed Property, the Agreed Value of such property or other asset reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property or other asset is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership's Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case as determined and required by the Treasury Regulations promulgated under Section 704(b) of the Code.
"Net Income" means, for any taxable period, the excess, if any, of the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall not include any items specially allocated under Section 6.1(d); provided, however, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).
"Net Loss" means, for any taxable period, the excess, if any, of the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall not include any items specially allocated under Section 6.1(d);
A-12
provided, however, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).
"Net Positive Adjustments" means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.
"Net Termination Gain" means, for any taxable period, (a) the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.4(b)) that are recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) the excess, if any, of the aggregate amount of Unrealized Gain over the aggregate amount of Unrealized Loss deemed recognized by the Partnership pursuant to Section 5.4(d) on the date of a Revaluation Event; provided, however, that the items included in the determination of Net Termination Gain shall not include any items of income, gain or loss specially allocated under Section 6.1(d).
"Net Termination Loss" means, for any taxable period, (a) the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.4(b)) that are recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) the excess, if any, of the aggregate amount of Unrealized Loss over the aggregate amount of Unrealized Gain deemed recognized by the Partnership pursuant to Section 5.4(b) on the date of a Revaluation Event; provided, however, that the items included in the determination of Net Termination Loss shall not include any items of income, gain or loss specially allocated under Section 6.1(d).
"Noncompensatory Option" has the meaning set forth in Treasury Regulation Section 1.721-2(f).
"Nonrecourse Built-in Gain" means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.
"Nonrecourse Deductions" means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.
"Nonrecourse Liability" has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).
"Notice" means a written request from a Holder pursuant to Section 7.12 which shall (a) specify the Registrable Securities intended to be registered, offered and sold by such Holder, (b) describe the nature or method of the proposed offer and sale of Registrable Securities, and (c) contain the undertaking of such Holder to provide all such information and materials and take all action as may be required or appropriate in order to permit the Partnership to comply with all applicable requirements and obligations in connection with the registration and disposition of such Registrable Securities pursuant to Section 7.12.
"Notice of Election to Purchase" has the meaning given such term in Section 15.1(b).
"Operating Expenditures" means all Partnership Group cash expenditures (or the Partnership's proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, compensation of employees, officers and directors of the General Partner, reimbursement of expenses of the General Partner and its Affiliates, debt service payments, Maintenance Capital
A-13
Expenditures, repayment of Working Capital Borrowings and payments made in the ordinary course of business under any Hedge Contracts, subject to the following:
(a) repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of "Operating Surplus" shall not constitute Operating Expenditures when actually repaid;
(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;
(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (iii) distributions to Partners, (iv) repurchases of Partnership Interests, other than repurchases of Partnership Interests by the Partnership to satisfy obligations under employee benefit plans or reimbursement of expenses of the General Partner for purchases of Partnership Interests by the General Partner to satisfy obligations under employee benefit plans, or (v) any other expenditures or payments using the proceeds of the Initial Public Offering as described under "Use of Proceeds" in the IPO Registration Statement; and
(d) (i) amounts paid in connection with the initial purchase of a Hedge Contract shall be amortized over the life of such Hedge Contract and (ii) payments made in connection with the termination of any Hedge Contract prior to the expiration of its scheduled settlement or termination date shall be included in equal quarterly installments over the remaining scheduled life of such Hedge Contract.
"Operating Surplus" means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,
(a) the sum of (i) $30.0 million, (ii) all cash receipts of the Partnership Group (or the Partnership's proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions and the termination of Hedge Contracts (provided that cash receipts from the termination of a Hedge Contract prior to its scheduled settlement or termination date shall be included in Operating Surplus in equal quarterly installments over the remaining scheduled life of such Hedge Contract), (iii) all cash receipts of the Partnership Group (or the Partnership's proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings and (iv) the amount of cash distributions from Operating Surplus paid during the Construction Period (including incremental Incentive Distributions) on Construction Equity, less
(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period, (ii) the amount of cash reserves (or the Partnership's proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to provide funds for future Operating Expenditures, and (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional Working Capital Borrowings; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.
A-14
Notwithstanding the foregoing, "Operating Surplus" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.
"Opinion of Counsel" means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner or to such other person selecting such counsel or obtaining such opinion.
"Option Closing Date" means the date or dates on which any Common Units are sold by the Partnership to the IPO Underwriters upon exercise of the Over-Allotment Option.
"Organizational Limited Partner" has the meaning given such term in the Recitals.
"Original Agreement" has the meaning given such term in the Recitals.
"Outstanding" means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership's books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class, all Partnership Interests owned by or for the benefit of such Person or Group shall not be entitled to be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i), provided that, upon or prior to such acquisition, the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership with the prior approval of the Board of Directors.
"Over-Allotment Option" means the over-allotment option granted to the IPO Underwriters by the Partnership pursuant to the IPO Underwriting Agreement.
"Partner Nonrecourse Debt" has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).
"Partner Nonrecourse Debt Minimum Gain" has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).
"Partner Nonrecourse Deductions" means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.
"Partners" means the General Partner and the Limited Partners.
"Partnership" means JP Energy Partners LP, a Delaware limited partnership.
"Partnership Group" means, collectively, the Partnership and its Subsidiaries.
"Partnership Interest" means any equity interest, including any class or series of equity interest, in the Partnership, which shall include any Limited Partner Interests but shall exclude the General Partner Interest and any Derivative Partnership Interests.
"Partnership Minimum Gain" means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).
A-15
"Partnership Register" means a register maintained on behalf of the Partnership by the General Partner, or, if the General Partner so determines, by the Transfer Agent as part of the Transfer Agent's books and transfer records, with respect to each class of Partnership Interests in which all Record Holders and transfers of such class of Partnership Interests are registered or otherwise recorded.
"Per Unit Capital Amount" means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.
"Percentage Interest" means, as of any date of determination, (a) as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder, by (B) the total number of Outstanding Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.5, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right and the General Partner Interest shall at all times be zero.
"Person" means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.
"Plan of Conversion" has the meaning given such term in Section 14.1.
"Pro Rata" means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, (c) when used with respect to holders of Incentive Distribution Rights, apportioned among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder, and (d) when used with respect to Holders who have requested to include Registrable Securities in a Registration Statement pursuant to Section 7.12(a) or 7.12(b), apportioned among all such Holders in accordance with the relative number of Registrable Securities held by each such holder and included in the Notice relating to such request.
"Purchase Date" means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.
"Quarter" means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership which includes the Closing Date, the portion of such fiscal quarter after the Closing Date.
"Rate Eligible Holder" means a Limited Partner subject to United States federal income taxation on the income generated by the Partnership. A Limited Partner that is an entity not subject to United States federal income taxation on the income generated by the Partnership shall be deemed a Rate Eligible Holder so long as all of the entity's beneficial owners are subject to such taxation.
"Recapture Income" means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.
"Record Date" means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to receive notice of, or entitled to exercise rights in respect of, any lawful action of Limited Partners (including voting) or
A-16
(b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.
"Record Holder" means (a) with respect to any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the Partnership's close of business on a particular Business Day or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the Partnership's close of business on a particular Business Day.
"Redeemable Interests" means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.
"Registrable Security" means any Partnership Interest other than the General Partner Interest; provided, however, that any Registrable Security shall cease to be a Registrable Security: (a) at the time a Registration Statement covering such Registrable Security is declared effective by the Commission or otherwise becomes effective under the Securities Act, and such Registrable Security has been sold or disposed of pursuant to such Registration Statement; (b) at the time such Registrable Security may be disposed of pursuant to Rule 144 (or any successor or similar rule or regulation under the Securities Act); (c) when such Registrable Security is held by a Group Member; and (d) at the time such Registrable Security has been sold in a private transaction in which the transferor's rights under Section 7.12 of this Agreement have not been assigned to the transferee of such securities.
"Registration Statement" has the meaning given such term in Section 7.12(a) of this Agreement.
"Remaining Net Positive Adjustments" means, as of the end of any taxable period, (a) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (i) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (ii) the sum of those Partners' Share of Additional Book Basis Derivative Items for each prior taxable period, and (b) with respect to the holders of Incentive Distribution Rights, the excess of (i) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (ii) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.
"Required Allocations" means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi) , Section 6.1(d)(vii) or Section 6.1(d)(ix).
"Reset MQD" has the meaning given such term in Section 5.10(e).
"Reset Notice" has the meaning given such term in Section 5.10(b).
"Retained Converted Subordinated Unit" has the meaning given such term in Section 5.4(c)(ii).
"Revaluation Event" means an event that results in adjustment of the Carrying Value of each Partnership property pursuant to Section 5.4(d).
"ROFO Agreement" means that certain Right of First Offer Agreement, dated as of [ • ], 2014, among the General Partner, the Partnership and JP Energy Development LP, a Delaware limited partnership, as such agreement may be amended, supplemented or restated from time to time.
"Second Amended and Restated Partnership Agreement" has the meaning given such term in the Recitals.
"Second Liquidation Target Amount" has the meaning given such term in Section 6.1(c)(i)(E).
"Second Target Distribution" means $0.40625 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2014, it means the product of $0.40625
A-17
multiplied by a fraction, the numerator of which is equal to the number of days in such period and the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.10, Section 6.6 and Section 6.9.
"Securities Act" means the Securities Act of 1933, as amended, supplemented or restated from time to time, and any successor to such statute.
"Selling Holder" means a Holder who is selling Registrable Securities pursuant to the procedures in Section 7.12 of this Agreement.
"Share of Additional Book Basis Derivative Items" means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (a) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders' Remaining Net Positive Adjustments as of the end of such taxable period bear to the Aggregate Remaining Net Positive Adjustments as of that time, and (b) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such taxable period bear to the Aggregate Remaining Net Positive Adjustments as of that time.
"Special Approval" means approval by a majority of the members of the Conflicts Committee.
"Sponsor" means Lonestar Midstream Holdings, LLC, a Delaware limited liability company.
"Subordinated Unit" means a Limited Partner Interest having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term "Subordinated Unit" does not include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.
"Subordination Period" means the period commencing on the Closing Date and expiring on the first to occur of the following dates:
(a) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending September 30, 2017 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case in respect of such periods and (B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units and Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such periods on a Fully Diluted Weighted Average Basis, and (ii) there are no Cumulative Common Unit Arrearages.
(b) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending September 30, 2015 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case with respect to the four-Quarter period immediately preceding such date equaled or exceeded 150% of the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any
A-18
other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case in respect of such period, and (B) the Adjusted Operating Surplus for the four-Quarter period immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Common Units and Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis, plus the corresponding Incentive Distributions and (ii) there are no Cumulative Common Unit Arrearages.
(c) the date on which the General Partner is removed in a manner described in Section 11.4.
For the period after the closing of this offering through December 31, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.
"Subsidiary" means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof; or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.
"Surviving Business Entity" has the meaning given such term in Section 14.2(b).
"Target Distributions" means, collectively, the First Target Distribution, Second Target Distribution and Third Target Distribution.
"Third Target Distribution" means $0.48750 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2014, it means the product of $0.48750 multiplied by a fraction, the numerator of which is equal to the number of days in such period and the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Sections 5.10, 6.6 and 6.9.
"Trading Day" means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted for trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City are not legally required to be closed.
"Transaction Documents" has the meaning given such term in Section 7.1(b).
"transfer" has the meaning given such term in Section 4.4(a).
"Transfer Agent" means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the General Partner to act as registrar and transfer agent for any class of Partnership Interests in accordance with the Exchange Act and the rules of the National Securities Exchange on which such Partnership Interests are listed (if any); provided, however, that, if no such Person is appointed as registrar and transfer agent for any class
A-19
of Partnership Interests, the General Partner shall act as registrar and transfer agent for such class of Partnership Interests.
"Treasury Regulation" means the United States Treasury regulations promulgated under the Code.
"Underwritten Offering" means (a) an offering pursuant to a Registration Statement in which Partnership Interests are sold to an underwriter on a firm commitment basis for reoffering to the public (other than the Initial Public Offering), (b) an offering of Partnership Interests pursuant to a Registration Statement that is a "bought deal" with one or more investment banks, and (c) an "at-the-market" offering pursuant to a Registration Statement in which Partnership Interests are sold to the public through one or more investment banks or managers on a best efforts basis.
"Unit" means a Partnership Interest that is designated by the General Partner as a "Unit" and shall include Common Units and Subordinated Units but shall not include (i) the General Partner Interest or (ii) Incentive Distribution Rights.
"Unit Majority" means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units.
"Unitholders" means the Record Holders of Units.
"Unpaid MQD" has the meaning given such term in Section 6.1(c)(i)(B).
"Unrealized Gain" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).
"Unrealized Loss" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).
"Unrecovered Initial Unit Price" means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.
"Unrestricted Person" means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an "Unrestricted Person" for purposes of this Agreement from time to time.
"U.S. GAAP" means United States generally accepted accounting principles, as in effect from time to time, consistently applied.
"Withdrawal Opinion of Counsel" has the meaning given such term in Section 11.1(b).
"Working Capital Borrowings" means borrowings incurred pursuant to a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to the Partners; provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from the date of such borrowings other than from additional Working Capital Borrowings.
A-20
Section 1.2 Construction. Unless the context requires otherwise: (a) any
pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the
singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the
terms "include," "includes," "including" or words of like import shall be deemed to be followed by the words "without limitation"; and (d) the terms "hereof," "herein" or "hereunder" refer to
this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in
any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. To the
fullest extent permitted by law, any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in
good faith shall, in each case, be conclusive and binding on all Record Holders, each other Person or Group who acquires an interest in a Partnership Interest and all other Persons for all purposes.
Section 2.1 Formation. The Former General Partner and the Organizational Limited Partner previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act. Thereafter the Former General Partner, the Limited Partners party to the Original Agreement and the Partnership amended and restated the Original Agreement in its entirety in the form of the Amended and Restated Partnership Agreement and subsequent thereto the General Partner, the Limited Partners party to the Amended and Restated Partnership Agreement and the Partnership amended and restated the Amended and Restated Partnership Agreement in its entirety in the form of the Second Amended and Restated Partnership Agreement. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties, liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.
Section 2.2 Name. The name of the Partnership shall be "JP Energy Partners LP". Subject to
applicable law, the Partnership's business may be conducted under any other name
or names as determined by the General Partner, including the name of the General Partner. The words "Limited Partnership," "L.P.," "Ltd." or similar words or letters shall be included in the
Partnership's name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time
to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.
Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and
until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at Corporation Trust Center,
1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The
Corporation Trust Company. The principal office of the Partnership shall be located at 600 East Las Colinas Boulevard, Suite 200, Irving, Texas 75039, or such other place as the General Partner
may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner
determines to be necessary or appropriate. The address of the General Partner shall be 600 East Las Colinas Boulevard, Suite 200, Irving, Texas 75039, or such other place as the General Partner
may from time to time designate by notice to the Limited Partners.
Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the
Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of
any
A-21
corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve the conduct by the Partnership of any business and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity and the General Partner in determining whether to propose or approve the conduct by the Partnership of any business shall be permitted to do so in its sole and absolute discretion.
Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things
necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance
and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.
Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of
Limited Partnership in accordance with the Delaware Act and shall continue in
existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a
separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.
Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or
mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and
no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of
the Partnership, the General Partner, one or more of its Affiliates or one or more nominees of the General Partner or its Affiliates, as the General Partner may determine. The General Partner hereby
declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees of the General Partner or
its Affiliates shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that
the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of
which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of
the Partnership's designated Affiliates as soon as reasonably practicable; provided further, that, prior to the withdrawal or removal of the General
Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide
for the use of such assets in a manner satisfactory to any successor General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective
of the name in which record title to such Partnership assets is held.
A-22
ARTICLE III
RIGHTS OF LIMITED PARTNERS
Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.
Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall
participate in the operation, management or control (within the meaning of the Delaware Act) of the
Partnership's business, transact any business in the Partnership's name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General
Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member,
general partner, agent or trustee of a Group Member, in its capacity as such, shall be deemed to be participating in the control of the business of the Partnership by a limited partner of the
Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under
this Agreement.
Section 3.3 Rights of Limited Partners.
(a) Each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner's interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner's own expense:
(i) to obtain from the General Partner either (A) the Partnership's most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K or (B) if the Partnership is no longer subject to the reporting requirements of the Exchange Act, the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act (provided that the foregoing materials shall be deemed to be available to a Limited Partner in satisfaction of the requirements of this Section 3.3(a)(i) if posted on or accessible through the Partnership's or the Commission's website);
(ii) to obtain a current list of the name and last known business, residence or mailing address of each Partner; and
(iii) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto.
(b) To the fullest extent permitted by law, the rights to information granted the Limited Partners pursuant to Section 3.3(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners and each other Person or Group who acquires an interest in the Partnership hereby agrees to the fullest extent permitted by law that they do not have any rights as Partners or interest holders to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.3(a).
(c) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.3).
(d) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Record Holders, each other Person or Group who acquires an interest in a Partnership
A-23
Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person or Group.
ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP
INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
Section 4.1 Certificates. Record Holders of Partnership Interests and, where appropriate, Derivative Partnership Interests, shall be recorded in the Partnership Register and ownership of such interests shall be evidenced by a physical Certificate or book entry notation in the Partnership Register. Notwithstanding anything to the contrary in this Agreement, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by physical Certificates. Certificates, if any, shall be executed on behalf of the Partnership by the Chief Executive Officer, President, Chief Financial Officer or any Senior Vice President or Vice President and the Secretary, any Assistant Secretary, or other authorized officer of the General Partner, and shall bear the legend set forth in Section 4.8(f). The signatures of such officers upon a Certificate may, to the extent permitted by law, be facsimiles. In case any officer who has signed or whose signature has been placed upon such Certificate shall have ceased to be such officer before such Certificate is issued, it may be issued by the Partnership with the same effect as if he or she were such officer at the date of its issuance. If a Transfer Agent has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that, if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c) , if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.6, the Record Holders of such Subordinated Units (a) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing the Common Units into which such Record Holder's Subordinated Units converted, or (b) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing the Common Units into which such Record Holders' Subordinated Units converted. With respect to any Partnership Interests that are represented by physical Certificates, the General Partner may determine that such Partnership Interests will no longer be represented by physical Certificates and may, upon written notice to the holders of such Partnership Interests and subject to applicable law, take whatever actions it deems necessary or appropriate to cause such Partnership Interests to be registered in book entry or global form and may cause such physical Certificates to be cancelled or deemed cancelled.
Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.
(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.
A-24
(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued, if the Record Holder of the Certificate:
(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;
(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;
(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and
(iv) satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.
If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, to the fullest extent permitted by law, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.
(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.
The names and addresses of Unitholders as they appear in the Partnership Register shall be the official list of Record Holders of the Partnership Interests for all purposes. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person or Group, regardless of whether the Partnership or the General Partner shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person or Group in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Person on the other, such representative Person shall be the Limited Partner with respect to such Partnership Interest upon becoming the Record Holder in accordance with Section 10.1(c) and have the rights and obligations of a Partner hereunder as, and to the extent, provided herein, including Section 10.1(d).
Section 4.4 Transfer Generally.
(a) The term "transfer," when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns all or any part of its General Partner Interest to another Person and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the
A-25
holder of a Limited Partner Interest assigns all or a part of such Limited Partner Interest to another Person who is or becomes a Limited Partner as a result thereof, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.
(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void, and the Partnership shall have no obligation to effect any such transfer or purported transfer.
(c) Nothing contained in this Agreement shall be construed to prevent or limit a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of such Person's shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or such Limited Partner and the term "transfer" shall not include any such disposition.
Section 4.5 Registration and Transfer of Limited Partner Interests.
(a) The General Partner shall maintain, or cause to be maintained by the Transfer Agent in whole or in part, the Partnership Register on behalf of the Partnership.
(b) The General Partner shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are duly endorsed and surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, however, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of this Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder's instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered. Upon the proper surrender of a Certificate, such transfer shall be recorded in the Partnership Register.
(c) Upon the receipt of proper transfer instructions from the Record Holder of uncertificated Partnership Interests, such transfer shall be recorded in the Partnership Register.
(d) Except as provided in Section 4.9, by acceptance of any Limited Partner Interests pursuant to a transfer in accordance with this Article IV, each transferee of a Limited Partner Interest (including any nominee, or agent or representative acquiring such Limited Partner Interests for the account of another Person or Group) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the Partnership Register and such Person becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) makes the consents, acknowledgements and waivers contained in this Agreement and (v) shall be deemed to certify that the transferee is not an Ineligible Holder, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.
A-26
(e) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner, (vi) provisions of applicable law including the Securities Act, and (vii) Section 4.9, Limited Partner Interests shall be freely transferable.
(f) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.
Section 4.6 Transfer of the General Partner's General Partner Interest.
(a) Subject to Section 4.6(c) below, prior to December 31, 2024, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person or (iii) is pursuant to a bona fide foreclosure by the lenders under any debt instrument with respect to which the General Partner is an obligor or guarantor.
(b) Subject to Section 4.6(c) below, on or after December 31, 2024, the General Partner may transfer all or any part of its General Partner Interest without the approval of any Limited Partner or any other Person.
(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest owned by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.
Section 4.7 Transfer of Incentive Distribution Rights. The General Partner or any other holder
of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without the approval of any
Limited Partner or any other Person.
Section 4.8 Restrictions on Transfers.
(a) Except as provided in Section 4.8(e), notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed). The
A-27
Partnership may issue stop transfer instructions to any Transfer Agent in order to implement any restriction on transfer contemplated by this Agreement.
(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes (to the extent not already so treated or taxed) or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.
(c) The transfer of an IDR Reset Common Unit that was issued in connection with an IDR Reset Election pursuant to Section 5.10 shall be subject to the restrictions imposed by Section 6.8(b) and 6.8(c).
(d) The transfer of a Subordinated Unit or a Common Unit resulting from the conversion of a Subordinated Unit shall be subject to the restrictions imposed by Section 6.7(b) and Section 6.7(c).
(e) Except for Section 4.9, nothing in this Agreement shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.
(f) Each Certificate or book entry evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:
THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF JP ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE TRANSFERRED IF SUCH TRANSFER (AS DEFINED IN THE PARTNERSHIP AGREEMENT) WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF JP ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE JP ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE GENERAL PARTNER OF JP ENERGY PARTNERS LP MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF JP ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THIS SECURITY MAY BE SUBJECT TO ADDITIONAL RESTRICTIONS ON ITS TRANSFER PROVIDED IN THE PARTNERSHIP AGREEMENT. COPIES OF SUCH AGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORD OF THIS SECURITY TO THE SECRETARY OF THE GENERAL PARTNER AT THE PRINCIPAL EXECUTIVE OFFICES OF THE PARTNERSHIP. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.
A-28
Section 4.9 Eligibility Certificates; Ineligible Holders.
(a) The General Partner may upon demand or on a regular basis require Limited Partners, and transferees of Limited Partner Interests in connection with a transfer, to execute an Eligibility Certificate or provide other information as is necessary for the General Partner to determine if any such Limited Partners or transferees are Ineligible Holders.
(b) If any Limited Partner (or its beneficial owners) fails to furnish to the General Partner within 30 days of its request an Eligibility Certificate and other information related thereto, or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner or a transferee of a Limited Partner is an Ineligible Holder, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10 or the General Partner may refuse to effect the transfer of the Limited Partner Interests to such transferee. In addition, the General Partner shall be substituted for any Limited Partner that is an Ineligible Holder as the Limited Partner in respect of the Ineligible Holder's Limited Partner Interests.
(c) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.
(d) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder's share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of its Limited Partner Interest (representing the right to receive its share of such distribution in kind).
(e) At any time after an Ineligible Holder can and does certify that it no longer is an Ineligible Holder, it may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.10, such Ineligible Holder upon approval of the General Partner, shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of such Limited Partner Interests.
(f) If at any time a transferee of a Partnership Interest fails to furnish an Eligibility Certificate or any other information requested by the General Partner pursuant to Section 4.9 within 30 days of such request, or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that such transferee is an Ineligible Holder, the Partnership may, unless the transferee establishes to the satisfaction of the General Partner that such transferee is not an Ineligible Holder, prohibit and void the transfer, including by placing a stop order with the Transfer Agent.
Section 4.10 Redemption of Partnership Interests of Ineligible Holders.
(a) If at any time a Limited Partner fails to furnish an Eligibility Certificate or any other information requested within the period of time specified in Section 4.9, or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred his Limited Partner Interests to a Person who is not an Ineligible Holder and
A-29
who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:
(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at such Limited Partner's last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which such Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.
(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.
(iii) The Limited Partner or such Limited Partner's duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Limited Partner or transferee at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).
(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.
(b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee, agent or representative of a Person determined to be an Ineligible Holder.
(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement and the transferor provides notice of such transfer to the General Partner. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that such transferee is not an Ineligible Holder. If the transferee fails to make such certification within 30 days after the request and, in any event, before the redemption date, such redemption shall be effected from the transferee on the original redemption date.
ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1 Contributions by the General Partner and the Existing Limited Partners.
(a) Prior to the Closing Date, the General Partner and the Existing Limited Partners made capital contributions in exchange for Partnership Interests. The General Partner hereby continues as general partner of the Partnership and each Existing Limited Partner hereby continues as a Limited Partner of the Partnership.
A-30
(b) The general partner interest owned by the General Partner pursuant to the Second Amended and Restated Partnership Agreement is hereby converted into a non-economic management interest, and the General Partner shall continue to own the Incentive Distribution Rights, the rights and obligations of which are set forth in this Agreement.
Section 5.2 Contributions by Limited Partners.
(a) On the Closing Date and pursuant to the IPO Underwriting Agreement, each IPO Underwriter contributed cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the IPO Underwriting Agreement.
(b) Upon the exercise, if any, of the Over-Allotment Option, (i) each IPO Underwriter shall contribute cash to the Partnership on the Option Closing Date in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the IPO Underwriting Agreement and (ii) the Partnership shall, subject to the Delaware Act, redeem an equivalent number of Common Units from the Sponsor, all as set forth in the IPO Underwriting Agreement.
(c) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units and Subordinated Units issued to each Existing Limited Partner in exchange for such Partnership Interests held by such Existing Limited Partner, as contemplated by Section 5.6 and Section 5.7 of the Second Amended and Restated Partnership Agreement and described in the IPO Prospectus and Section 5.1(c) above, and (ii) the Common Units issued to the IPO Underwriters as described in subparagraphs (a) and (b) of this Section 5.2.
(d) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.
Section 5.3 Interest and Withdrawal.
No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.
(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). The Capital Account balance attributable to the Common Units and Subordinated Units issued to the Existing Limited Partners prior to or in connection with the Initial Public Offering shall be deemed to equal the product of the number of Common Units and Subordinated Units issued to such Existing Limited Partner and the Initial Unit Price for each such Common Unit and Subordinated Unit (and the initial Capital Account balance attributable to each such Common Unit and Subordinated Unit shall equal its Initial Unit Price). The initial Capital Account balance attributable to the Common Units issued to the IPO Underwriters pursuant to Section 5.2(b) shall equal the product of the number of Common Units so issued to the IPO Underwriters and the Initial Unit Price for each Common Unit (and the initial Capital Account balance attributable to each such Common Unit shall equal its Initial Unit Price). The initial Capital Account attributable to the General Partner Interest and the Incentive Distribution Rights shall be zero.
A-31
Thereafter, the Capital Account shall in respect of each such Partnership Interest be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.
(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners' Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided that:
(i) Solely for purposes of this Section 5.4, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership or disregarded entity for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership or disregarded entity for federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.
(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.
(iii) The computation of all items of income, gain, loss and deduction shall be made, except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that may be made by the Partnership. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.
(iv) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.4(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain, and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.
(v) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership's Carrying Value with respect to such property as of such date.
(vi) An item of income of the Partnership that is described in Section 705(a)(1)(B) of the Code (with respect to items of income that are exempt from tax) shall be treated as an item of income for the purpose of this Section 5.4(b), and an item of expense of the Partnership that is described in Section 705(a)(2)(B) of the Code (with respect to expenditures that are not deductible and not chargeable to capital accounts), shall be treated as an item of deduction for the purpose of this Section 5.4(b) .
A-32
(vii) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.
(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).
(c) (i) Except as otherwise provided in this Section 5.4(c), a transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.
(ii) Subject to Section 6.7(b), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.6 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.4(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any converted Subordinated Units ("Retained Converted Subordinated Units") or Subordinated Units. Following any such allocation, the transferor's Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee's Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.
(iii) Subject to Section 6.8(b), immediately prior to the transfer of an IDR Reset Common Unit by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.4(c)(iii) apply), the Capital Account maintained for such Person with respect to its IDR Reset Common Units will (A) first, be allocated to the IDR Reset Common Units to be transferred in an amount equal to the product of (x) the number of such IDR Reset Common Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any IDR Reset Common Units. Following any such allocation, the transferor's Capital Account, if any, maintained with respect to the retained IDR Reset Common Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee's Capital Account established with respect to the transferred IDR Reset Common Units will have a balance equal to the amount allocated under clause (A) above.
(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of a Noncompensatory
A-33
Option, the issuance of Partnership Interests as consideration for the provision of services, the issuance of IDR Reset Common Units pursuant to Section 5.11, or the conversion of the General Partner's Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of each Partner and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated; provided, however, that in the event of the issuance of a Partnership Interest pursuant to the exercise of a Noncompensatory Option where the right to share in Partnership capital represented by such Partnership Interest differs from the consideration paid to acquire and exercise such option, the Carrying Value of each Partnership property immediately after the issuance of such Partnership Interest shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property and the Capital Accounts of the Partners shall be adjusted in a manner consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(s); provided further, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, in the event of an issuance of a Noncompensatory Option to acquire a de minimis Partnership Interest, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. If, upon the occurrence of a Revaluation Event described in this Section 5.4(d), a Noncompensatory Option of the Partnership is outstanding, the Partnership shall adjust the Carrying Value of each Partnership property in accordance with Treasury Regulation Sections 1.704-1(b)(2)(iv)(f)(1) and 1.704-1(b)(2)(iv)(h)(2). In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of a Revaluation Event resulting from the exercise of a Noncompensatory Option, immediately after the issuance of the Partnership Interest acquired pursuant to the exercise of such Noncompensatory Option if required pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(1)) shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time, and the amount of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.
(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any
A-34
item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of a distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.
Section 5.5 Issuances of Additional Partnership Interests.
(a) The Partnership may issue additional Partnership Interests (other than General Partner Interests) and Derivative Partnership Interests for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.
(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest; (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by Certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.
(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Partnership Interests pursuant to this Section 5.5, (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.10, (iv) reflecting admission of such additional Limited Partners in the Partnership Register as the Record Holders of such Limited Partner Interests and (v) all additional issuances of Partnership Interests and Derivative Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests or Derivative Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or Derivative Partnership Interests or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.
(d) No fractional Units shall be issued by the Partnership.
Section 5.6 Conversion of Subordinated Units.
(a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the expiration of the Subordination Period.
(b) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7.
A-35
Section 5.7 Limited Preemptive Right. Except as provided in this Section 5.7 and in Section 5.10 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or
other
similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. Other than with respect to the issuance of Partnership Interests in
connection with the Initial Public Offering, the General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership
Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary
to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.
Section 5.8 Splits and Combinations.
(a) Subject to Section 5.8(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.
(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice (or such shorter periods as required by applicable law). The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.
(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of Partnership Interests represented by Certificates, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.
(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.5(d) and this Section 5.8(d), each fractional Unit shall be rounded to the nearest whole Unit (with fractional Units equal to or greater than a 0.5 Unit being rounded to the next higher Unit).
Section 5.9 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited
Partner Interests issued pursuant to, and in accordance with the requirements of, this
Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected
by Sections 17-303, 17-607 or 17-804 of the Delaware Act.
Section 5.10 Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.
(a) Subject to the provisions of this Section 5.10, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in
A-36
interest of the Incentive Distribution Rights) shall have the right, at any time when there are no Subordinated Units Outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(v) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the "IDR Reset Election") to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.10(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the "IDR Reset Common Units") derived by dividing (i) the average amount of the aggregate cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for the two full Quarters immediately preceding the giving of the Reset Notice (the number of Common Units determined by such quotient is referred to herein as the "Aggregate Quantity of IDR Reset Common Units"). If at the time of any IDR Reset Election the General Partner and its Affiliates are not the holders of a majority in interest of the Incentive Distribution Rights, then the IDR Reset Election shall be subject to the prior written concurrence of the General Partner that the conditions described in the immediately preceding sentence have been satisfied. The making of the IDR Reset Election in the manner specified in this Section 5.10 shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.10(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive IDR Reset Common Units on the basis specified above, without any further approval required by the General Partner or the Unitholders other than as set forth in this Section 5.10(a), at the time specified in Section 5.10(c) unless the IDR Reset Election is rescinded pursuant to Section 5.10(d).
(b) To exercise the right specified in Section 5.10(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the "Reset Notice") to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership's determination of the Aggregate Quantity of IDR Reset Common Units that each holder of Incentive Distribution Rights will be entitled to receive.
(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of IDR Reset Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such IDR Reset Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.
(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the IDR Reset Common Units to be issued pursuant to this Section 5.10 on or before the 30th calendar day following the Partnership's receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership's receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such
A-37
Partnership Interests into Common Units within not more than 12 months following the Partnership's receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).
(e) The Minimum Quarterly Distribution and the Target Distributions shall be adjusted at the time of the issuance of IDR Reset Common Units or other Partnership Interests pursuant to this Section 5.10 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership's receipt of the Reset Notice (the "Reset MQD"), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.
(f) Upon the issuance of IDR Reset Common Units pursuant to Section 5.10(a), the Capital Account maintained with respect to the Incentive Distribution Rights will (i) first, be allocated to IDR Reset Common Units in an amount equal to the product of (A) the Aggregate Quantity of IDR Reset Common Units and (B) the Per Unit Capital Amount for an Initial Common Unit, and (ii) second, as to any remaining balance in such Capital Account, will be retained by the holder of the Incentive Distribution Rights. If there is not sufficient capital associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an Initial Common Unit to the IDR Reset Common Units in accordance with clause (i) of this Section 5.10(f), the IDR Reset Common Units shall be subject to Sections 6.1(d)(x)(B) and (C).
ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership's items of income, gain, loss and deduction (computed in accordance with Section 5.4(b)) for each taxable period shall be allocated among the Partners as provided herein below.
(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:
(i) First, to the Unitholders to which Net Loss has been allocated pursuant to the proviso provision of Section 6.1(b), in proportion to the allocations of Net Loss pursuant to the proviso provision of Section 6.1(b), until the aggregate Net Income allocated pursuant to this Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated pursuant to the proviso provision of Section 6.1(b) for all previous taxable periods; and
(ii) Thereafter, to the Unitholders, Pro Rata.
(b) Net Loss. After giving effect to the special allocations set forth in Section 6.1(d), Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Loss for such taxable period shall be allocated to the Unitholders, Pro Rata; provided, however, that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account) and such Net Loss shall instead be allocated to the Unitholders with positive Adjusted Capital Account balances in proportion to such positive balances.
A-38
(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.
(i) Except as provided in Section 6.1(c)(iv), and subject to the provisions set forth in the last sentence of this Section 6.1(c)(i), Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated in the following order and priority:
(A) First, to each Unitholder having a deficit balance in its Adjusted Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Adjusted Capital Accounts of all Unitholders, until each such Unitholder has been allocated Net Termination Gain equal to any such deficit balance in its Adjusted Capital Account and the Net Income allocated pursuant to Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate Net Loss allocated pursuant to the proviso provision of Section 6.1(b) for all previous taxable periods and Net Termination Loss allocated pursuant to the applicable proviso provision of Section 6.1(c)(ii)(C) or Section 6.1(c)(iii) for all previous taxable periods;
(B) Second, to all Unitholders holding Common Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter referred to as the "Unpaid MQD") and (3) any then existing Cumulative Common Unit Arrearage;
(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit into a Common Unit, to all Unitholders holding Subordinated Units, Pro Rata, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;
(D) Fourth, to all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter after the Closing Date or the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) for such period (the sum of subclauses (1), (2), (3) and (4) is hereinafter referred to as the "First Liquidation Target Amount");
(E) Fifth, 15% to the holders of the Incentive Distribution Rights, Pro Rata, and 85% to all Unitholders, Pro Rata, until the Capital Account in respect of each Common
A-39
Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter after the Closing Date or the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) for such period (the sum of subclauses (1) and (2) is hereinafter referred to as the "Second Liquidation Target Amount");
(F) Sixth, 25% to the holders of the Incentive Distribution Rights, Pro Rata, and 75% to all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter after the Closing Date or the most recent IDR Reset Election, if any, over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv) for such period; and
(G) Finally, 50% to the holders of the Incentive Distribution Rights, Pro Rata, and 50% to all Unitholders, Pro Rata.
Notwithstanding the foregoing provisions in this Section 6.1(c)(i), the General Partner may adjust the amount of any Net Termination Gain arising in connection with a Revaluation Event that is allocated to the holders of Incentive Distribution Rights in a manner that will result (i) in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value and (ii) to the greatest extent possible, the Capital Account with respect to the Incentive Distribution Rights that are Outstanding prior to such Revaluation Event being equal to the amount of Net Termination Gain that would be allocated to the holders of the Incentive Distribution Rights pursuant to this Section 6.1(c)(i) if the Capital Accounts with respect to all Partnership Interests that were Outstanding immediately prior to such Revaluation Event and the Carrying Value of each Partnership property were equal to zero.
(ii) Except as otherwise provided by Section 6.1(c)(iii) or Section 6.1(c)(iv), Net Termination Loss shall be allocated:
(A) First, if Subordinated Units remain Outstanding, to all Unitholders holding Subordinated Units, Pro Rata, until the Adjusted Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;
(B) The balance, if any, to all Unitholders holding Common Units, Pro Rata.
(iii) Net Termination Loss deemed recognized pursuant to clause (b) of the definition of Net Termination Loss as a result of a Revaluation Event prior to the conversion of the last Outstanding Subordinated Unit and prior to the Liquidation Date shall be allocated:
(A) First, to the Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding equals the Event Issue Value; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account);
(B) Second, to all Unitholders holding Subordinated Units, Pro Rata; provided, however, that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(B) to the extent such allocation would cause any Unitholder to have a
A-40
deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and
(C) The balance, if any, to the Unitholders with positive Adjusted Capital Account balances in proportion to such positive balances.
(iv) If (A) a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), (B) a Net Termination Gain or Net Termination Loss subsequently occurs (other than as a result of a Revaluation Event) prior to the conversion of the last Outstanding Subordinated Unit and (C) after tentatively making all allocations of such Net Termination Gain or Net Termination Loss provided for in Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable, the Capital Account in respect of each Common Unit does not equal the amount such Capital Account would have been if Section 6.1(c)(iii) had not been part of this Agreement and all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable, then items of income, gain, loss and deduction included in such Net Termination Gain or Net Termination Loss, as applicable, shall be specially allocated to all Unitholders in a manner that will, to the maximum extent possible, cause the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.
(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period in the following order:
(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner's Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d) (i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.
(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provision. For purposes of this Section 6.1(d), each Partner's Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) and other than an allocation pursuant to Section 6.1(d)(i), Section 6.1(d)(vi) and Section 6.1(d)(vii) with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.
A-41
(iii) Priority Allocations.
(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit for a taxable period exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit within the same taxable period (the amount of the excess, an "Excess Distribution" and the Unit with respect to which the greater distribution is paid, an "Excess Distribution Unit"), then there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution.
(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable period.
(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, however, that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.
(v) Gross Income Allocation. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, however, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.
(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Unitholders Pro Rata. If the General Partner determines that the Partnership's Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that satisfies such requirements.
A-42
(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, the Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.
(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated as determined by the General Partner in accordance with any permissible method under Treasury Regulation 1.752-3(a)(3).
(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.
(x) Economic Uniformity; Changes in Law.
(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period ("Final Subordinated Units") in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (1) the number of Final Subordinated Units held by such Partner and (2) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.4(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.
(B) With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.4(d) during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.10, after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest
A-43
extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.10 equaling the product of (1) the Aggregate Quantity of IDR Reset Common Units and (2) the Per Unit Capital Amount for an Initial Common Unit.
(C) With respect to any taxable period during which an IDR Reset Common Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Common Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Common Unit to an amount equal to the Per Unit Capital Amount for an Initial Common Unit.
(D) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (1) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (2) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (3) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(D) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.
(xi) Curative Allocation.
(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.
A-44
(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.
(xii) Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:
(A) The General Partner shall allocate Additional Book Basis Derivative Items consisting of depreciation, amortization, depletion or any other form of cost recovery (other than Additional Book Basis Derivative Items included in Net Termination Gain or Net Termination Loss) with respect to any Adjusted Property to the Unitholders, Pro Rata, and the holders of Incentive Distribution Rights, all in the same proportion as the Net Termination Gain or Net Termination Loss resulting from the Revaluation Event that gave rise to such Additional Book Basis Derivative Items was allocated to them pursuant to Section 6.1(c).
(B) If a sale or other taxable disposition of an Adjusted Property, including, for this purpose, inventory ("Disposed of Adjusted Property") occurs other than in connection with an event giving rise to Net Termination Gain or Net Termination Loss, the General Partner shall allocate (1) items of gross income and gain (aa) away from the holders of Incentive Distribution Rights and (bb) to the Unitholders, or (2) items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items with respect to the Disposed of Adjusted Property (determined in accordance with the last sentence of the definition of Additional Book Basis Derivative Items) treated as having been allocated to the Unitholders pursuant to this Section 6.1(d)(xii)(B) exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For purposes of this Section 6.1(d)(xii)(B), the Unitholders shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.
(C) Net Termination Loss in an amount equal to the lesser of (1) such Net Termination Loss and (2) the Aggregate Remaining Net Positive Adjustments shall be allocated in such a manner, as determined by the General Partner, that to the extent possible, the Capital Account balances of the Partners will equal the amount they would have been had no prior Book-Up Events occurred, and any remaining Net Termination Loss shall be allocated pursuant to Section 6.1(c) hereof. In allocating Net Termination Loss pursuant to this Section 6.1(d)(xii)(C), the General Partner shall attempt, to the extent possible, to cause the Capital Accounts of the Unitholders, on the one hand, and holders of the Incentive Distribution Rights, on the other hand, to equal the amount they would equal if (i) the Carrying Values of the Partnership's property had not been previously adjusted in connection with any prior Book-Up Events, (ii) Unrealized Gain and Unrealized Loss (or, in the case of a liquidation, actual gain or loss) with respect to
A-45
such Partnership Property were determined with respect to such unadjusted Carrying Values, and (iii) any resulting Net Termination Gain had been allocated pursuant to Section 6.1(c)(i) (including, for the avoidance of doubt, taking into account the provisions set forth in the last sentence of Section 6.1(c)(i)).
(D) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the "lower tier partnership"), the General Partner may make allocations similar to those described in Sections 6.1(d)(xii) (A) through (C) to the extent the General Partner determines such allocations are necessary to account for the Partnership's allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii).
(xiii) Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.
Section 6.2 Allocations for Tax Purposes.
(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of "book" income, gain, loss or deduction is allocated pursuant to Section 6.1.
(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined to be appropriate by the General Partner (taking into account the General Partner's discretion under Section 6.1(d)(x)(D)); provided, however, that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.
(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership's property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner
A-46
Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.
(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.
(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.
(f) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, that such items for the period beginning on the Closing Date and ending on the last day of the month in which the last Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; provided further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.
(g) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.
(h) If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).
Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.
(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2014, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. The Record Date for the first distribution of Available Cash shall not be prior to the final closing of the Over-Allotment Option. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately
A-47
preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be "Capital Surplus." All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act and other applicable law, notwithstanding any other provision of this Agreement.
(b) Notwithstanding Section 6.3(a) (but subject to the last sentence of Section 6.3(a)), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.
(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners, as determined appropriate under the circumstances by the General Partner.
(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership's liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.
Section 6.4 Distributions of Available Cash from Operating Surplus.
(a) During the Subordination Period. Available Cash with respect to any Quarter within the
Subordination Period that is deemed to be Operating Surplus pursuant to the provisions
of Section 6.3 or 6.5 shall be distributed as follows, except as otherwise required in respect of
additional Partnership Interests issued pursuant to Section 5.5(b):
(i) First, to the Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
(ii) Second, to the Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;
(iii) Third, to the Unitholders holding Subordinated Units, Pro Rata, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
(iv) Fourth, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
(v) Fifth, (A) 15% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 85% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;
(vi) Sixth, (A) 25% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 75% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and
(vii) Thereafter, (A) 50% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 50% to all Unitholders, Pro Rata;
A-48
provided, however, that if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).
(b) After the Subordination Period. Available Cash with respect to any Quarter after the Subordination
Period that is deemed to be Operating Surplus pursuant to the provisions
of Section 6.3 or Section 6.5 shall be distributed as follows, except as otherwise
required in respect of additional Partnership Interests issued pursuant to Section 5.5(b):
(i) First, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
(ii) Second, to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
(iii) Third, (A) 15% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 85% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;
(iv) Fourth, (A) 25% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 75% to all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and
(v) Thereafter, (A) 50% to the holders of the Incentive Distribution Rights, Pro Rata, and (B) 50% to all Unitholders, Pro Rata;
provided, however, that if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(v).
Section 6.5 Distributions of Available Cash from Capital Surplus. Available Cash that is deemed
to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall be
distributed, unless the provisions of Section 6.3 require otherwise, to the Unitholders, Pro Rata, until a hypothetical holder of a Common Unit
acquired on the Closing Date has received with respect to such Common Unit distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price.
Available Cash that is deemed to be Capital Surplus shall then be distributed to all Unitholders holding Common Units, Pro Rata, until there has been distributed in respect of each Common Unit then
Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance
with Section 6.4.
Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.
(a) The Minimum Quarterly Distribution, Target Distributions, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests in accordance with Section 5.8. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution and Target Distributions shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, as the case may be, by a fraction, the numerator of
A-49
which is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and the denominator of which is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.
(b) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall also be subject to adjustment pursuant to Section 5.10 and Section 6.9.
Section 6.7 Special Provisions Relating to the Holders of Subordinated Units.
(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.6, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such converted Subordinated Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.4(c)(ii) , 6.1(d)(x)(A), 6.7(b) and 6.7(c).
(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.6 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder's Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.4(c)(ii)(B).
(c) The holder of a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.6 or Section 11.4 shall not be issued a Common Unit Certificate pursuant to Section 4.1 (if the Common Units are represented by Certificates) and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.4(c)(ii), 6.1(d)(x) and 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.
Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights.
(a) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (1) shall (x) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (y) have a Capital Account as a Partner pursuant to Section 5.4 and all other provisions related thereto and (2) shall not (x) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (y) be entitled to any distributions other than as provided in Sections 6.4(a)(v), (vi) and (vii) , Sections 6.4(b)(iii), (iv) and (v), and Section 12.4 or (z) be allocated items of income, gain, loss or deduction other than as specified in this Article VI; provided, however, that for the avoidance of doubt, the foregoing shall not preclude the Partnership from making any other payments or distributions in connection with other actions permitted by this Agreement.
A-50
(b) A Unitholder shall not be permitted to transfer an IDR Reset Common Unit (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder's Capital Account with respect to the retained IDR Reset Common Units would be negative after giving effect to the allocation under Section 5.4(c)(iii).
(c) A holder of an IDR Reset Common Unit that was issued in connection with an IDR Reset Election pursuant to Section 5.10 shall not be issued a Common Unit Certificate pursuant to Section 4.1 (if the Common Units are evidenced by Certificates) or evidence of the issuance of uncertificated Common Units, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of such holder, until such time as the General Partner determines, based on advice of counsel, that each such IDR Reset Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.8(c), the General Partner may take whatever steps are required to provide economic uniformity to such IDR Reset Common Units in preparation for a transfer of such IDR Reset Common Units, including the application of Section 5.4(c)(iii), Section 6.1(d)(x)(B), or Section 6.1(d)(x)(C); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.
Section 6.9 Entity-Level Taxation. If legislation is enacted or the official interpretation of
existing legislation is modified by a governmental authority, which after giving effect to such
enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member
prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, at its option,
reduce the Minimum Quarterly Distribution and the Target Distributions by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the
"Incremental Income Taxes"), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General
Partner elects to reduce the Minimum Quarterly Distribution and the Target Distributions for any Quarter with respect
to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group's aggregate liability (the "Estimated Incremental
Quarterly Tax Amount") for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for
Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental
Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, Second Target
Distribution and Third Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times
(b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of
Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash
with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.
ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have
A-51
any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:
(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for Partnership Interests, and the incurring of any other obligations;
(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;
(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);
(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;
(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);
(vi) the distribution of Partnership cash;
(vii) the selection and dismissal of officers, employees, agents, internal and outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;
(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;
(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;
A-52
(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);
(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Partnership Interests;
(xiv) the undertaking of any action in connection with the Partnership's participation in the management of any Group Member; and
(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.
(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each Record Holder and each other Person who may acquire an interest in a Partnership Interest or that is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the IPO Underwriting Agreement, the ROFO Agreement and the other agreements described in or filed as exhibits to the IPO Registration Statement that are related to the transactions contemplated by the IPO Registration Statement (collectively, the "Transaction Documents") (in the case of each agreement other than this Agreement, without giving effect to any amendments, supplements or restatements thereof entered into after the date such Person becomes bound by the provisions of this Agreement); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the IPO Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.
Section 7.2 Certificate of Limited Partnership. The General Partner has caused the Certificate
of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware
Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the
formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in
which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to
and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have
limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.3(a), the
General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited
Partnership, any qualification document or any amendment thereto to any Limited Partner.
A-53
Section 7.3 Restrictions on the General Partner's Authority to Sell Assets of the Partnership Group.
Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination or sale of ownership interests of the Partnership's Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner's ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.
Section 7.4 Reimbursement of and Other Payments to the General Partner.
(a) Except as provided in this Section 7.4, and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.
(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner, to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses reasonably allocable to the Partnership Group or otherwise incurred by the General Partner or its Affiliates in connection with managing and operating the Partnership Group's business and affairs (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7. Any allocation of expenses to the Partnership by the General Partner in a manner consistent with its or its Affiliates' past business practices and, in the case of assets regulated by FERC, then applicable accounting and allocation methodologies generally permitted by FERC for rate-making purposes (or in the absence of then-applicable methodologies permitted by FERC, consistent with the most-recently applicable methodologies), shall be deemed to have been made in good faith.
(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Interests or Derivative Partnership Interests), or cause the Partnership to issue Partnership Interests or Derivative Partnership Interests in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of officers, employees, consultants and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any officers, employees, consultants and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner
A-54
hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner's General Partner Interest pursuant to Section 4.6.
(d) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.
(e) The General Partner and its Affiliates may enter into an agreement to provide services to any Group Member for a fee or otherwise than for cost.
Section 7.5 Outside Activities.
(a) The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the IPO Registration Statement, (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (C) the guarantee of, and mortgage, pledge, or encumbrance of any or all of its assets in connection with, any indebtedness of any Group Member.
(b) Subject to the terms of Section 7.5(c), each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.
(c) Subject to the terms of Section 7.5(a) and Section 7.5(b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership, all Partners and all other Persons bound by this Agreement, (ii) it shall not be a breach of any duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership or any other Group Member and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or in equity, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for any Group Member, shall have any duty to communicate or offer such opportunity to any Group Member, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person who is bound by this Agreement for breach of any duty existing in law, in equity or
A-55
otherwise by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires such opportunity for itself, directs such opportunity to another Person or does not communicate such opportunity or information to any Group Member, provided that such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.
(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Interests acquired by them. The term "Affiliates" when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.
Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.
(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm's-length basis (without reference to the lending party's financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term "Group Member" shall include any Affiliate of a Group Member that is controlled by the Group Member.
(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).
(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners existing hereunder, or existing at law, in equity or otherwise by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner's Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.
(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity on behalf of or for the benefit of the Partnership; provided, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by
A-56
a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to any Affiliate of the General Partner (other than a Group Member), or to any other Indemnitee, with respect to any such Person's obligations pursuant to the Transaction Documents (other than this Agreement). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.
(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.
(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee's capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the IPO Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.
(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership's or any other Group Member's activities or such Person's activities on behalf of the Partnership or any other Group Member, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.
(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute "fines" within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.
(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.
(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.
A-57
(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.
(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.
Section 7.8 Liability of Indemnitees.
(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who are bound by this Agreement for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was unlawful.
(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.
(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership's business or affairs shall not be liable to the Partnership or to any Partner or to any other Persons who are bound by this Agreement for its good faith reliance on the provisions of this Agreement.
(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.
Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.
(a) Unless a lesser standard otherwise is provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval or (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates). If the General Partner does not submit the solution or course of action as provided in either clauses (i) or (ii) in the preceding sentence, then any such solution or course of action shall be governed by Section 7.9(b) below. The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action
A-58
that has not received Special Approval or Unitholder approval. Whenever the General Partner makes a determination to refer or to not refer any potential conflict of interest to the Conflicts Committee for Special Approval, to seek or not to seek Unitholder approval or to adopt a resolution or course of action that has not received Special Approval or Unitholder approval, then, the General Partner shall be entitled, to the fullest extent permitted by law, to make such determination free of any duty or obligation whatsoever to the Partnership or any Limited Partner, and the General Partner shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard or duty imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in making such determination shall be permitted to do so at its option. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith and if the Board of Directors determines that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, then it shall be presumed that, in making its determination, the Board of Directors acted in good faith. In any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging any action by the Conflicts Committee with respect to any matter referred to the Conflicts Committee for Special Approval or any determination by the Board of Directors that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, the Person bringing or prosecuting such proceeding shall have the burden of overcoming the presumption that the Conflicts Committee or the Board of Directors, as applicable, acted in good faith. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the IPO Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement or any such duty.
(b) Whenever the General Partner or the Board of Directors, or any committee thereof (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any Affiliate of the General Partner causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless a lesser standard is provided for in this Agreement or the determination, action or omission has been approved as provided in Section 7.9(a)(ii), the General Partner, the Board of Directors or such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith. Whenever the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) or any Affiliate of the General Partner makes a determination or takes or declines to take any other action, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless a lesser standard is provided for in this Agreement or the determination, action or omission has been approved as provided in Section 7.9(a)(ii), the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) or any Affiliate of the General Partner shall make such determination or take or decline to take such other action in good faith. The foregoing and other lesser standards governing any determination, action or omission provided for in this Agreement are the sole and exclusive standards governing any such determinations, actions and omissions of the General Partner, the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) and any Affiliate of the General Partner, and no such Person shall be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard (all of which duties, obligations and standards are hereby eliminated, waived and disclaimed), under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, or under the Delaware Act or any other law, rule or regulation or at equity. Any such determination, action or omission by the General Partner, the Board of Directors of the General Partner or any committee thereof (including the Conflicts Committee) or of any Affiliates of the General Partner, will for all purposes be presumed to have been in good faith. In any proceeding brought by or on behalf of
A-59
the Partnership, any Limited Partner, or any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement, challenging such determination, action or omission, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or omission was not in good faith. A determination or other action or inaction will conclusively be deemed to be in "good faith" for all purposes of this Agreement, if the Person or Persons making such determination or taking or declining to take such other action subjectively believe that the determination or other action or inaction is in the best interests of the Partnership Group.
(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty or obligation whatsoever to the Partnership or any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the Person or Persons making such determination or taking or declining to take such other action shall be permitted to do so in their sole and absolute discretion. By way of illustration and not of limitation, whenever the phrase, "the General Partner at its option," or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.
(d) The General Partner's organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner's general partner, if the General Partner is a partnership.
(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.
(f) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner, and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.
(g) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.
A-60
Section 7.10 Other Matters Concerning the General Partner and Other Indemnitees.
(a) The General Partner and any other Indemnitee may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.
(b) The General Partner and any other Indemnitee may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner or such Indemnitee, respectively, reasonably believes to be within such Person's professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.
(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.
Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or Derivative Partnership Interests; provided that, except as permitted pursuant to Section 4.10 or with Special Approval, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Articles IV and X.
Section 7.12 Registration Rights of the General Partner and its Affiliates.
(a) Demand Registration. Upon receipt of a Notice from any Holder at any time after the 180th day after the Closing Date, the Partnership shall file with the Commission as promptly as reasonably practicable a registration statement under the Securities Act (each, a "Registration Statement") providing for the resale of the Registrable Securities, which may, at the option of the Holder giving such Notice, be a Registration Statement that provides for the resale of the Registrable Securities from time to time pursuant to Rule 415 under the Securities Act. The Partnership shall not be required pursuant to this Section 7.12(a) to file more than one Registration Statement in any twelve-month period nor to file more than three Registration Statements in the aggregate. The Partnership shall use commercially reasonable efforts to cause such Registration Statement to become effective as soon as reasonably practicable after the initial filing of the Registration Statement and to remain effective and available for the resale of the Registrable Securities by the Selling Holders named therein until the earlier of (i) six months following such Registration Statement's effective date and (ii) the date on which all Registrable Securities covered by such Registration Statement have been sold. In the event one or more Holders request in a Notice to dispose of a number of Registrable Securities that such Holder or Holders reasonably anticipates will result in gross proceeds of at least $30,000,000 in the aggregate pursuant to a Registration Statement in an Underwritten Offering, the Partnership shall retain underwriters that are reasonably acceptable to such Selling Holders in order to permit such Selling Holders to effect such disposition through an Underwritten Offering; provided, however, that the Partnership shall have the exclusive right to select the bookrunning managers. The Partnership and such Selling Holders shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Registrable Securities therein. No Holder may participate in the Underwritten Offering unless it agrees to sell its Registrable Securities
A-61
covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. In the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering.
(b) Piggyback Registration. At any time after the 180th day after the Closing Date, if the Partnership shall propose to file a Registration Statement (other than pursuant to a demand made pursuant to Section 7.12(a)) for an offering of Partnership Interests for cash (other than an offering relating solely to an employee benefit plan, an offering relating to a transaction on Form S-4 or an offering on any registration statement that does not permit secondary sales), the Partnership shall notify all Holders of such proposal at least five Business Days before the proposed filing date. The Partnership shall use commercially reasonable efforts to include such number of Registrable Securities held by any Holder in such Registration Statement as each Holder shall request in a Notice received by the Partnership within two Business Days of such Holder's receipt of the notice from the Partnership. If the Registration Statement about which the Partnership gives notice under this Section 7.12(b) is for an Underwritten Offering, then any Holder's ability to include its desired amount of Registrable Securities in such Registration Statement shall be conditioned on such Holder's inclusion of all such Registrable Securities in the Underwritten Offering; provided that, in the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. In connection with any such Underwritten Offering, the Partnership and the Selling Holders involved shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Registrable Securities therein. No Holder may participate in the Underwritten Offering unless it agrees to sell its Registrable Securities covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering. The Partnership shall have the right to terminate or withdraw any Registration Statement or Underwritten Offering initiated by it under this Section 7.12(b) prior to the effective date of the Registration Statement or the pricing date of the Underwritten Offering, as applicable.
(c) Sale Procedures. In connection with its obligations under this Section 7.12, the Partnership shall:
(i) furnish to each Selling Holder (A) as far in advance as reasonably practicable before filing a Registration Statement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such
A-62
information prior to filing a Registration Statement or supplement or amendment thereto, and (B) such number of copies of such Registration Statement and the prospectus included therein and any supplements and amendments thereto as such Persons may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities covered by such Registration Statement; provided, however, that the Partnership will not have any obligation to provide any document pursuant to clause (B) hereof that is available on the Commission's website;
(ii) if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by a Registration Statement under the securities or blue sky laws of such jurisdictions as the Selling Holders or, in the case of an Underwritten Offering, the managing underwriter, shall reasonably request; provided, however, that the Partnership will not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action that would subject it to general service of process in any jurisdiction where it is not then so subject;
(iii) promptly notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the filing of a Registration Statement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Registration Statement or any post-effective amendment thereto, when the same has become effective; and (B) any written comments from the Commission with respect to any Registration Statement or any document incorporated by reference therein and any written request by the Commission for amendments or supplements to a Registration Statement or any prospectus or prospectus supplement thereto;
(iv) immediately notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the occurrence of any event or existence of any fact (but not a description of such event or fact) as a result of which the prospectus or prospectus supplement contained in a Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading (in the case of the prospectus contained therein, in the light of the circumstances under which a statement is made); (B) the issuance or threat of issuance by the Commission of any stop order suspending the effectiveness of a Registration Statement, or the initiation of any proceedings for that purpose; or (C) the receipt by the Partnership of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, subject to Section 7.12(f) , the Partnership agrees to, as promptly as practicable, amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to take such other reasonable action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto; and
(v) enter into customary agreements and take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, in order to expedite or facilitate the disposition of the Registrable Securities, including the provision of comfort letters and legal opinions as are customary in such securities offerings.
(d) Suspension. Each Selling Holder, upon receipt of notice from the Partnership of the happening of any event of the kind described in Section 7.12(c)(iv), shall forthwith discontinue disposition of the Registrable Securities by means of a prospectus or prospectus supplement until such Selling Holder's receipt of the copies of the supplemented or amended prospectus contemplated by such subsection or until it is advised in writing by the Partnership that the use of the prospectus may be
A-63
resumed, and has received copies of any additional or supplemental filings incorporated by reference in the prospectus.
(e) Expenses. Except as set forth in an underwriting agreement for the applicable Underwritten Offering or as otherwise agreed between a Selling Holder and the Partnership, all costs and expenses of a Registration Statement filed or an Underwritten Offering that includes Registrable Securities pursuant to this Section 7.12 (other than underwriting discounts and commissions on Registrable Securities and fees and expenses of counsel and advisors to Selling Holders) shall be paid by the Partnership.
(f) Delay Right. Notwithstanding anything to the contrary herein, if the General Partner determines that the Partnership's compliance with its obligations in this Section 7.12 would be detrimental to the Partnership because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone compliance with such obligations for a period of not more than six months; provided, however, that such right may not be exercised more than twice in any 24-month period.
(g) Indemnification.
(i) In addition to and not in limitation of the Partnership's obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless each Selling Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, "Indemnified Persons") from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(g) as a "claim" and in the plural as "claims") based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus under which any Registrable Securities were registered or sold under the Securities Act, or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.
(ii) Each Selling Holder shall, to the fullest extent permitted by law, indemnify and hold harmless the Partnership, the General Partner, the General Partner's officers and directors and each Person who controls the Partnership or the General Partner (within the meaning of the Securities Act) and any agent thereof to the same extent as the foregoing indemnity from the Partnership to the Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in a Registration Statement, prospectus or free writing prospectus relating to the Registrable Securities held by such Selling Holder.
A-64
(iii) The provisions of this Section 7.12(g) shall be in addition to any other rights to indemnification or contribution that a Person entitled to indemnification under this Section 7.12(g) may have pursuant to law, equity, contract or otherwise.
(h) Specific Performance. Damages in the event of breach of Section 7.12 by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each party, in addition to and without limiting any other remedy or right it may have, will have the right to seek an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives, to the fullest extent permitted by law, any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such party from pursuing any other rights and remedies at law or in equity that such party may have.
Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership's sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.
ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership's business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.3(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the register of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device, provided that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to
A-65
account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.
Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.
(a) Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership (or such shorter period as required by the Commission), the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership's or the Commission's website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.
(b) Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 50 days after the close of each Quarter (or such shorter period as required by the Commission) except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership's or the Commission's website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.
Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or year that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership's taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.
(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner's determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest
A-66
will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.
(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.
Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner shall designate the "tax matters partner" (as defined in Section 6231(a)(7) of the Code). The tax matters partner is authorized and required to represent the Partnership (at the Partnership's expense) in connection with all examinations of the Partnership's affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the tax matters partner and to do or refrain from doing any or all things reasonably required by the tax matters partner to conduct such proceedings.
Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code, or established under any foreign law. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or Section 12.4(c) in the amount of such withholding from such Partner.
ARTICLE X
ADMISSION OF PARTNERS
Section 10.1 Admission of Limited Partners.
(a) The Existing Limited Partners were admitted to the Partnership as Limited Partners prior to the Closing Date.
(b) Upon the issuance by the Partnership of Common Units to the IPO Underwriters in connection with the Initial Public Offering as described in Article V, such Persons shall, by acceptance of such Partnership Interests, and upon becoming the Record Holders of such Partnership Interests, be admitted to the Partnership as Initial Limited Partners in respect of the Common Units issued to them and be bound by this Agreement, all with or without execution of this Agreement by such Persons. The General Partner, in its capacity as the holder of the Incentive Distribution Rights, and the Existing Limited Partners, with respect to their Common Units and Subordinated Units, will continue as Limited Partners in respect of those Partnership Interests.
(c) By acceptance of any Limited Partner Interests transferred in accordance with Article IV or acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger, consolidation or conversion pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee, agent or representative acquiring such Limited Partner Interests for the account of another Person or Group, who shall be subject to Section 10.1(c) below) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when such Person becomes the Record Holder of the Limited Partner Interests so transferred or acquired, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) shall be deemed to represent that the transferee or acquirer has the capacity, power
A-67
and authority to enter into this Agreement and (iv) shall be deemed to make any consents, acknowledgements or waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and becoming the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.9.
(d) With respect to any Limited Partner that holds Units representing Limited Partner Interests for another Person's account (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such Limited Partner shall, in exercising the rights of a Limited Partner in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, take all action as a Limited Partner by virtue of being the Record Holder of such Units at the direction of the Person who is the beneficial owner, and the Partnership shall be entitled to assume such Limited Partner is so acting without further inquiry.
(e) The name and mailing address of each Record Holder shall be listed on the books of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable).
(f) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).
Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to (a) the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or (b) the transfer of the General Partner Interest pursuant to Section 4.6; provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor is hereby authorized to and shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.
Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.
ARTICLE XI
WITHDRAWAL OR REMOVAL OF PARTNERS
Section 11.1 Withdrawal of the General Partner.
(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an "Event of Withdrawal");
A-68
(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;
(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;
(iii) The General Partner is removed pursuant to Section 11.2;
(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;
(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or
(vi) (A) if the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) if the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise upon the termination of the General Partner.
If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.
(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Eastern Time, on December 31, 2024 the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel ("Withdrawal Opinion of Counsel") that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Eastern Time, on December 31, 2024 the General Partner voluntarily withdraws by giving at least 90 days' advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its
A-69
Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner's withdrawal, a successor is not elected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.
Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units voting as a class and Unitholders holding a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.
Section 11.3 Interest of Departing General Partner and Successor General Partner.
(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates' general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates' Incentive Distribution Rights (collectively, the "Combined Interest") in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the
A-70
effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.
For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner's withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner's successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership's assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.
(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.
(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership's assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner's admission, the successor General Partner's interest in all Partnership distributions and allocations shall be its Percentage Interest.
A-71
Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages. Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist: (i) the Subordination Period will end and all Outstanding Subordinated Units held by any Person will immediately and automatically convert into Common Units on a one-for-one basis, provided (a) neither such Person nor any of its Affiliates voted any of its Units in favor of the removal and (b) such Person is not an Affiliate of the successor General Partner; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 6.7(c), (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the Combined Interest will immediately and automatically convert into Common Units in accordance with Section 11.3, provided the Departing General Partner is the holder, or is an affiliate of the holder, of the Combined Interest.
Section 11.5 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner's Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.
ARTICLE XII
DISSOLUTION AND LIQUIDATION
Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, to the fullest extent permitted by law, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:
(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and a Withdrawal Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;
(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;
(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or
(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.
Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon
(a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii)
and the failure of the Partners to select a successor to such
Departing General Partner pursuant to Section 11.1 or Section 11.2, then, to the maximum
extent permitted by law, within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to
the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth
in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth
A-72
above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:
(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;
(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and
(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;
provided, however, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner under the Delaware Act and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).
Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the
Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall
be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class.
The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days' prior notice and may be removed at any time, with or without cause, by notice of
removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. Upon dissolution, removal or resignation of the Liquidator,
a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least
a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be
deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner
provided herein shall have and may exercise, without further authorization or consent of any
of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the
exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and
functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.
Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the
Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over
such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:
(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership's assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership's assets would be
A-73
impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership's assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.
(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.
(c) All property and all cash in excess of that required to satisfy liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).
Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the
distribution of Partnership cash and property as provided in Section 12.4 in
connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the
State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.
Section 12.6 Return of Contributions. The General Partner shall not be personally liable for,
and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it
to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from
Partnership assets.
Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby
waives any right to partition of the Partnership property.
Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to
restore any negative balance in its Capital Account upon liquidation of the Partnership.
ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:
(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;
(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;
(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group
A-74
Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
(d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests in any material respect (except as permitted by subsection (g) of this Section 13.1), (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.8 or (iv) is required to effect the intent expressed in the IPO Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;
(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of "Quarter" and the dates on which distributions are to be made by the Partnership;
(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
(g) an amendment that (i) sets forth the designations, preferences, rights, powers and duties of any class or series of Partnership Interests or Derivative Partnership Interests issued pursuant to Section 5.5 or (ii) the General Partner determines to be necessary, appropriate or advisable in connection with the authorization or issuance of any class or series of Partnership Interests or Derivative Partnership Interests pursuant to Section 5.5;
(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;
(i) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 14.3;
(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a);
(k) a merger, conveyance or conversion pursuant to Section 14.3(d) or Section 14.3(e); or
(l) any other amendments substantially similar to the foregoing.
Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the
General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or
A-75
obligation to propose or approve any amendment to this Agreement and may decline to do so free of any duty or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and, in declining to propose or approve an amendment to this Agreement, to the fullest extent permitted by law, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to propose or approve any amendment to this Agreement shall be permitted to do so in its sole and absolute discretion. An amendment to this Agreement shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or Section 13.3, the holders of a Unit Majority, unless a greater or different percentage of Outstanding Units is required under this Agreement. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has posted or made accessible such amendment through the Partnership's or the Commission's website.
Section 13.3 Amendment Requirements.
(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage or (ii) in the case of Section 11.2 or Section 13.4, increasing such percentages, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute (x) in the case of a reduction as described in subclause (a)(i) hereof, not less than the voting requirement sought to be reduced, (y) in the case of an increase in the percentage in Section 11.2, not less than 90% of the Outstanding Units, or (z) in the case of an increase in the percentage in Section 13.4, not less than a majority of the Outstanding Units.
(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without the General Partner's consent, which consent may be given or withheld at its option.
(c) Except as provided in Section 14.3, and without limitation of the General Partner's authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.
(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(f), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.
(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.
A-76
Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this
Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the
Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating
that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the
meeting is proposed. No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call
from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements
governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send or cause to be sent a notice of the meeting to the Limited Partners. A
meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as
provided in Section 16.1. Limited Partners shall not be permitted to vote on matters that would cause the Limited Partners to be deemed to be
taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability under the Delaware Act or the law of any other
state in which the Partnership is qualified to do business. If any such vote were to take place, to the fullest extent permitted by law, it shall be deemed null and void to the extent necessary so as
not to jeopardize the Limited Partners' limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.
Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to
Section 13.4 shall be given to the Record Holders of the class or
classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1.
Section 13.6 Record Date. For purposes of determining the Limited Partners who are Record Holders
of the class or classes of Limited Partner Interests entitled to notice of or to vote at a
meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11, the General Partner shall set a Record Date,
which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any
National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National
Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which such Limited Partners are requested in
writing by the General Partner to give such approvals.
Section 13.7 Postponement and Adjournment. Prior to the date upon which any meeting of Limited
Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by
giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days
before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be
fixed unless such postponement shall be for more than 45 days. Any meeting of Limited Partners may be adjourned by the General Partner one or more times for any reason, including the failure of
a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No Limited Partner vote shall be required for any
adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned
to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment
is taken, unless such adjournment shall be for
A-77
more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.
Section 13.8 Waiver of Notice; Approval of Meeting. The transactions of any meeting of Limited
Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held
after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the
Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened;
and except that attendance at a meeting is not a waiver of any right to disapprove of any matters submitted for consideration or to object to the failure to submit for consideration any matters
required to be included in the notice of the meeting, but not so included, if such objection is expressly made at the beginning of the meeting.
Section 13.9 Quorum and Voting.
Except as otherwise provided by this Agreement or required by the rules or regulations of any National Securities Exchange on which the Common Units are admitted
to trading, or applicable law or pursuant to any regulation applicable to the Partnership or its Partnership Interests, the presence, in person or by proxy, of holders of a majority in voting power of
the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) entitled to vote at the meeting shall constitute a
quorum at a meeting of Limited Partners of such class or classes. Abstentions and broker non-votes in respect of such Units shall be deemed to be Units present at such meeting for purposes of
establishing a quorum. For all matters presented to the Limited Partners holding Outstanding Units at a meeting at which a quorum is present for which no minimum or other vote of Limited Partners is
required by any other provision of this Agreement, the rules or regulations of any National Securities Exchange on which the Common Units are admitted to trading, or applicable law or pursuant to any
regulation applicable to the Partnership or its Partnership Interests, a majority of the votes cast by the Limited Partners holding Outstanding Units shall be deemed to constitute the act of all
Limited Partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter). On any matter where a minimum or other vote of Limited Partners holding
Outstanding Units is provided by any other provision of this Agreement or required by the rules or regulations of any National Securities Exchange on which the Common Units are admitted to trading, or
applicable law or pursuant to any regulation applicable to the Partnership or its Partnership Interests, such minimum or other vote shall be the vote of Limited Partners required to approve such
matter (with the effect of abstentions and broker non-votes to be determined based on the vote of Limited Partners required to approve such matter; provided that if the effect of abstentions and
broker non-votes is not specified by such applicable rule, regulation or law, and there is no prevailing interpretation of such effect, then abstentions and broker non-votes shall be deemed to not
have been cast with respect to such matter; provided further, that, for the avoidance of doubt, with respect to any matter on which this Agreement requires the approval of a specified percentage of
the Outstanding Units, abstentions and broker non-votes shall be counted as votes against such matter). The Limited Partners present at a duly called or held meeting at which a quorum has been
established may continue to transact business until adjournment, notwithstanding the exit of enough Limited Partners to leave less than a quorum.
Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority
concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in
writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of
any proxies and the determination of any controversies, votes or challenges
arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any
A-78
meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the submission and revocation of approvals in writing.
Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that
may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing
setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units that would be necessary to authorize or take such action at a
meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the
Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without
a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any
action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the
Partnership does not vote all of the Outstanding Units held by such Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Outstanding Units that were not voted.
If approval of the taking of any permitted action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and
effect unless and until (a) approvals sufficient to take the action proposed are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the
action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are first deposited with the Partnership and (c) an Opinion of Counsel is delivered to
the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed
to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability, and (ii) is otherwise permissible
under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.
Section 13.12 Right to Vote and Related Matters.
(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of "Outstanding") shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.
(b) With respect to Units that are held for a Person's account by another Person that is the Record Holder (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), such Record Holder shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume such Record Holder is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.
A-79
(c) Notwithstanding anything in this Agreement to the contrary, the Record Holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter.
ARTICLE XIV
MERGER, CONSOLIDATION OR CONVERSION
Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America or any other country, pursuant to a written plan of merger or consolidation ("Merger Agreement") or a written plan of conversion ("Plan of Conversion"), as the case may be, in accordance with this Article XIV.
Section 14.2 Procedure for Merger, Consolidation or Conversion.
(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner; provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may so consent or decline to do so free of any duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to consent to any merger, consolidation or conversion of the Partnership shall be permitted to do so in its sole and absolute discretion.
(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:
(i) name and state or country of domicile of each of the business entities proposing to merge or consolidate;
(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the "Surviving Business Entity");
(iii) the terms and conditions of the proposed merger or consolidation;
(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (A) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;
A-80
(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;
(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, however, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and
(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.
(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:
(i) the name of the converting entity and the converted entity;
(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;
(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;
(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;
(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership;
(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;
(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and
(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.
Section 14.3 Approval by Limited Partners.
(a) Except as provided in Section 14.3(d) and Section 14.3(e), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent and, subject to any applicable requirements of Regulation 14A pursuant to the Exchange Act or successor provision, no other disclosure regarding the proposed merger, consolidation or conversion shall be required.
A-81
(b) Except as provided in Section 14.3(d) and Section 14.3(e), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.
(c) Except as provided in Section 14.3(d) and Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.
(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership's assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of limited liability under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) of any Limited Partner as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.
(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another limited liability entity if (i) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (iii) the Partnership is the Surviving Business Entity in such merger or consolidation, (iv) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (v) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.
(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving
A-82
Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.
Section 14.4 Certificate of Merger or Certificate of Conversion. Upon the required approval by
the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger
or certificate of conversion or other filing, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware or the appropriate filing office of any other
jurisdiction, as applicable, in conformity with the requirements of the Delaware Act or other applicable law.
Section 14.5 Effect of Merger, Consolidation or Conversion.
(a) At the effective time of the merger:
(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;
(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;
(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and
(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.
(b) At the effective time of the conversion:
(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;
(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;
(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;
(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;
(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior Partners without any need for substitution of parties; and
(vi) the Partnership Interests that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.
A-83
ARTICLE XV
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
Section 15.1 Right to Acquire Limited Partner Interests.
(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three Business Days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.
(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the applicable Transfer Agent or exchange agent notice of such election to purchase (the "Notice of Election to Purchase") and shall cause the Transfer Agent or exchange agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner), together with such information as may be required by law, rule or regulation, at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be filed and distributed as may be required by the Commission or any National Securities Exchange on which such Limited Partner Interests are listed. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption in exchange for payment, at such office or offices of the Transfer Agent or exchange agent as the Transfer Agent or exchange agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the Partnership Register shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent or exchange agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate or redemption instructions shall not have been surrendered for purchase or provided, respectively, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent or exchange agent of the Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the Partnership Register, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the
A-84
Record Holder of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the Record Holder of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).
(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent or exchange agent in exchange for payment of the amount described in Section 15.1(a) therefor, without interest thereon, in accordance with procedures set forth by the General Partner.
ARTICLE XVI
GENERAL PROVISIONS
Section 16.1 Addresses and Notices; Written Communications.
(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Except as otherwise provided herein, any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown in the Partnership Register, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing in the Partnership Register is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.
(b) The terms "in writing," "written communications," "written notice" and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.
Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all
information and take or refrain from taking action as may be necessary or appropriate to achieve
the purposes of this Agreement.
A-85
Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of
the parties hereto and their heirs, executors, administrators, successors, legal representatives
and permitted assigns.
Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties
hereto pertaining to the subject matter hereof and supersedes all prior agreements and
understandings pertaining thereto.
Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or
shall be enforceable by, any creditor of the Partnership.
Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any
covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy
consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.
Section 16.7 Third-Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall
be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to
those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a
third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.
Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together
shall constitute an agreement binding on all the parties hereto, notwithstanding that all
such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person
acquiring a Limited Partner Interest, pursuant to Section 10.1(a) or (b) without execution
hereof.
Section 16.9 Applicable Law; Forum; Venue and Jurisdiction.
(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.
(b) Each of the Partners and each Person or Group holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):
(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims; provided, however, any claims, suits, actions or proceedings over which the Court of Chancery of the State of Delaware does not have jurisdiction shall be brought in any other court in the State of Delaware having jurisdiction;
(ii) irrevocably submits to the exclusive jurisdiction of the courts of the State of Delaware in connection with any such claim, suit, action or proceeding;
A-86
(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the courts of the State of Delaware or of any other court to which proceedings in the courts of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;
(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and
(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, however, that nothing in this clause (v) shall affect or limit any right to serve process in any other manner permitted by law.
Section 16.10 Invalidity of Provisions. If any provision or part of a provision of this
Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality
and enforceability of the remaining provisions and/or parts thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and
construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provisions and/or part shall be reformed so that it would be valid,
legal and enforceable to the maximum extent possible.
Section 16.11 Consent of Partners. Each Partner hereby expressly consents and agrees that,
whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or
consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.
Section 16.12 Facsimile and Email Signatures. The use of facsimile signatures and signatures
delivered by email in portable document format (.pdf) affixed in the name and on behalf of the transfer agent and
registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.
Section 16.13 Interpretation. To the fullest extent permitted by law, in the event of any
ambiguity or question of intent or interpretation arises, this Agreement will be construed as if
drafted jointly by the Partners and no presumption or burden of proof will arise favoring or disfavoring any Partner by virtue of the authorship of any of the provisions of this Agreement.
[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]
A-87
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.
| GENERAL PARTNER: | ||||
JP ENERGY GP II LLC |
||||
By: |
||||
|
|
||||
| Name: | ||||
| Title: | ||||
Signature Page to Third Amended and Restated Agreement of
Limited Partnership of JP Energy Partners LP
EXHIBIT A
to the Third Amended and Restated
Agreement of Limited Partnership of
JP Energy Partners LP
Certificate Evidencing Common Units
Representing Limited Partner Interests
in
JP Energy Partners LP
| No. | Common Units |
In accordance with Section 4.1 of the Third Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP, as amended, supplemented or restated from time to time (the "Partnership Agreement"), JP Energy Partners LP, a Delaware limited partnership (the "Partnership"), hereby certifies that (the "Holder") is the registered owner of Common Units representing limited partner interests in the Partnership (the "Common Units") transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 600 East Las Colinas Boulevard, Suite 200, Irving, Texas 75039. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.
THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF JP ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE TRANSFERRED IF SUCH TRANSFER (AS DEFINED IN THE PARTNERSHIP AGREEMENT) WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF JP ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE JP ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE GENERAL PARTNER OF JP ENERGY PARTNERS LP MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF JP ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THIS SECURITY MAY BE SUBJECT TO ADDITIONAL RESTRICTIONS ON ITS TRANSFER PROVIDED IN THE PARTNERSHIP AGREEMENT. COPIES OF SUCH AGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORD OF THIS SECURITY TO THE SECRETARY OF THE GENERAL PARTNER AT THE PRINCIPAL EXECUTIVE OFFICES OF THE PARTNERSHIP. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.
A-A-1
The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.
This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.
| Dated: | JP Energy Partners LP | |||||||
|
|
||||||||
By: |
JP Energy GP II LLC |
|||||||
By: |
||||||||
|
|
||||||||
By: |
||||||||
|
|
||||||||
| Countersigned and Registered by: | ||||
[ |
] |
|||
|
as Transfer Agent and Registrar |
||||
By: |
||||
|
Authorized Signature |
||||
A-A-2
[Reverse of Certificate]
The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:
| TEN COM—as tenants in common | UNIF GIFT TRANSFERS MIN ACT | |
TEN ENT—as tenants by the entireties |
Custodian (Cust) (Minor) |
|
| JT TEN—as joint tenants with right of survivorship and not as tenants in common | under Uniform Gifts/Transfers to CD Minors Act (State) |
Additional abbreviations, though not in the above list, may also be used.
A-A-3
ASSIGNMENT
OF COMMON UNITS OF
JP ENERGY PARTNERS LP
FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto
|
(Please print or typewrite name and address of assignee) |
(Please insert Social Security or other identifying number of assignee) |
|||
Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of JP Energy Partners LP. |
||||
Date: |
NOTE: The signature to any endorsement |
|||
|
|
hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change. | |||
(Signature) |
||||
(Signature) |
||||
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15 |
||||
No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.
A-A-4
additive injection: Any materials incorporated in finished petroleum products in order to improve their performance in existing applications or to broaden the areas of their utility.
Bbl or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bbls/d: Stock tank barrels per day.
bio-diesel: A domestic, renewable fuel for diesel engines derived from natural oils.
blending services: Refers to the process by which various compounds are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel. These may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.
Bpd: One barrel per day.
Brent crude: A type of crude oil commonly used as a price benchmark.
butane: A hydrocarbon that is a gas under surface conditions and is found in natural gas.
catalyst: A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
CBOB, PBOB and RBOB: Refers to motor gasoline blending components intended for blending with oxygenates to produce finished conventional motor gasoline.
condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
crude oil: A mixture of hydrocarbons that exists in liquid phase in underground reservoirs.
dye-at-rack capability: Dye is injected into diesel products in order to mark the fuel as "off-road diesel," meaning that the diesel can be used for only off-road vehicles. The dye is mechanically injected at the time that diesel fuel is loaded from a refined products terminal to a transport truck and distinguishes taxable product from product that is not taxed.
end-user markets: The ultimate users and consumers of transported energy products.
ethanol: A clear, colorless, flammable oxygenated hydrocarbon that is used in the United States as a gasoline octane enhancer and oxygenate.
FERC: Federal Energy Regulatory Commission.
Gal or Gallon: A unit of volume for liquid measure equal to four quarts.
Gal/d: Gallons per day.
GHGs: Greenhouse gases.
hydraulic fracturing: A well stimulation method in which a high-pressure frac liquid is pumped down a well to fracture the reservoir rock adjacent to the wellbore.
liquid petroleum products: Products which are obtained from the processing of crude oil, natural gas and other hydrocarbon compounds.
B-1
Louisiana Light Sweet Crude: Refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur than sour crude oil. Sweet crude oil is typically more expensive than sour crude oil.
LPG or liquid petroleum gas: Refers to propane or butane.
MBbls: One thousand barrels.
MBbls/d: One thousand barrels per day.
MBoe: One thousand barrels of oil equivalent.
Mgal/d: One thousand gallons per day.
MMcfe: One million cubic feet equivalent.
natural gas liquids, or NGLs: The combination of ethane, propane, normal butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
oxygenate blending: The blending of substances which, when added to gasoline, increase the amount of oxygen in that gasoline blend.
play: A proven geological formation that contains commercial amounts of hydrocarbons.
propane: A hydrocarbon that is a gas under surface conditions and is found in natural gas.
refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residential fuel, that are produced by a refinery.
throughput: The volume of refined products transported or passing through a terminal or other facility during a particular period.
ultra-low sulphur diesel: Diesel fuel that has a maximum sulfur content of 15 parts per million.
vapor recovery units: A refinery unit to which gases and vaporized gasoline from various processing operations are charged to separate the mixed charged into desired intermediate qualities for further processing.
wellhead: The equipment at the surface of a well used to control the well's pressure. Also, the point at which the hydrocarbons and water exit the ground.
WTI: West Texas Intermediate, a type of crude oil commonly used as a price benchmark.
B-2
JP Energy Partners LP
13,750,000 Common Units
Representing Limited Partner Interests
Prospectus
, 2014
Barclays
BofA Merrill Lynch
RBC Capital Markets
Deutsche Bank Securities
BMO Capital Markets
Baird
Simmons & Company International
Stephens Inc.
Janney Montgomery Scott
Through and including , 2014 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.
PART II
Information Not Required in the Registration Statement
Item 13. Other Expenses of Issuance and Distribution
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NYSE filing fee, the amounts set forth below are estimates.
SEC registration fee |
$ | 42,770 | ||
FINRA filing fee |
35,000 | |||
NYSE listing fee |
125,000 | |||
Printing and engraving expenses |
250,000 | |||
Fees and expenses of legal counsel |
1,750,000 | |||
Accounting fees and expenses |
1,590,000 | |||
Transfer agent and registrar fees |
10,000 | |||
Miscellaneous |
197,230 | |||
Total |
$ | 4,000,000 | ||
- *
- To be filed by amendment.
Item 14. Indemnification of Directors and Officers
The section of the prospectus entitled "Our Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement in which we and certain of our affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended (the "Securities Act"), and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.
Item 15. Recent Sales of Unregistered Securities
During the past three years, we have sold or issued securities that were not registered under the Securities Act, as set forth below. No underwriters were involved in any of these issuances of securities. The issuances described below were made to investors in reliance upon the exemption from the registration requirements of the Securities Act provided by Rule 506 and Rule 701 promulgated thereunder, relative to transactions by an issuer not involving any public offering. All non-employee purchasers or recipients of our securities described below represented to us in connection with their purchase or receipt that they were accredited investors and were acquiring our equity securities for their own account for investment purposes only and not with a view to, or for sale in connection with, any distribution thereof. Additionally, the purchasers or recipients of our securities received written disclosures that the securities had not been registered under the Securities Act and that any resale must be made pursuant to a registration statement or an available exemption from such registration. All purchasers or recipients either received adequate information about us or had access, through employment or other relationships, to such information.
- •
- In connection with our formation, on May 6, 2010 we issued (i) 45 common units to JP Energy GP LLC, our predecessor general partner, and (ii) 474,375 common units to 31 private investors. The aggregate consideration for the issuances was $9,547,838.
II-1
- •
- In connection with an acquisition of assets, we issued 2,000 common units to the transferor of the assets and 7,500 common
units to two individuals as acquisition consideration on October 1, 2010. The aggregate consideration for the issuances was $190,000.
- •
- In connection with a capital call, we issued 158,125 common units to 24 private investors, all of whom were
pre-existing investors in the Partnership, on October 10, 2010. The aggregate consideration for the issuances was $3,182,613.
- •
- In connection with a capital call, we issued 209,819 common units to 22 private investors, 16 of whom were
pre-existing investors in the Partnership, on January 17, 2011. The aggregate consideration for the issuances was $4,220,131.
- •
- We issued 60,534 common units to three private investors on January 31, 2011. The aggregate consideration for the
issuances was $1,210,680.
- •
- We issued 1,622 common units to one private investor on February 1, 2011. The aggregate consideration for the
issuance was $32,440.
- •
- In connection with an acquisition of assets, we issued 7,500 common units as acquisition consideration on June 22,
2011. The aggregate consideration of the units at the time they were issued was $150,000.
- •
- In connection with a capital call, on June 27, 2011 we issued 78,030 common units to seven private investors, all
of whom who were pre-existing investors in the Partnership. The aggregate consideration for the issuances was $1,716,660.
- •
- In connection with our recapitalization by Lonestar Midstream Holdings, LLC ("Lonestar"), on June 27, 2011 we
(i) retired 992,005 outstanding common units and issued 992,005 Class B common units in their place, (ii) issued 524,746 Series A preferred units to Lonestar and
(iii) issued a one-third membership interest in JP Energy GP II LLC, our successor general partner, to Lonestar. The aggregate consideration for the issuances to Lonestar was
$11,544,412.
- •
- In connection with a funding by Lonestar, we issued 552,348 Series B preferred units to Lonestar on
September 8, 2011. The aggregate consideration for the issuance was $12,151,656.
- •
- In connection with a funding by Lonestar, we issued 59,270 Series C preferred units and 49,821 Class A
common units to Lonestar on December 9, 2011. The aggregate consideration for the issuance was $2,400,002.
- •
- Between March 2012 and June 2012, in connection with our general partner's entry into employment agreements with seven
employees, we issued 75,000 restricted Class B common units, subject to the terms and conditions of award agreements between us and each employee.
- •
- In connection with a funding by Lonestar, we issued 2,113,637 Class A common units to Lonestar on June 6,
2012. The aggregate consideration for the issuance was $46,500,014.
- •
- On June 27, 2012, we issued 15,000 Class B common units to a pre-existing investor after a
holder of our Class B common units surrendered a unit certificate representing 15,000 Class B common units in connection with a private sale of class B common units.
- •
- In connection with a funding by Lonestar and an acquisition of assets in July 2012, we issued (i) 1,977,273
Class A common units to Lonestar on July 19, 2012 and (b) 666,667 Class C common units to four private parties as acquisition consideration on July 20, 2012. The
aggregate consideration for the issuance to Lonestar was $43,500,006. The aggregate consideration of the units at the time they were issued to the four private parties was $20,000,010.
- •
- In connection with a funding by Lonestar, we issued 2,272,727 Class A common units to Lonestar on August 2, 2012. The aggregate consideration for the issuance was $50,000,016.
II-2
- •
- On September 13, 2012, upon Lonestar's surrender of a certificate representing 49,821 Class A common units,
we issued (i) 46,821 Class A common units to Lonestar and (ii) 3,000 Class A common units to an independent contractor who provided services to an affiliate of Lonestar.
- •
- On September 19, 2012, we issued 50,000 restricted Class B common units to an employee of our general
partner pursuant to the earn-out provisions of the employee's employment agreement.
- •
- In connection with an acquisition of assets, we issued 2,500,000 Class C common units to four private parties on
November 27, 2012. We received cash consideration of $10,963,200 for 438,528 of the units issued on this date. The aggregate consideration of the remaining 2,061,472 units at the time they were
issued was $51,536,800.
- •
- In November and December 2012, in connection with our general partner's entry into employment agreements with three
employees, we issued 36,500 restricted Class B common units, subject to the terms and conditions of award agreements between us and each employee.
- •
- In connection with a funding by Lonestar, we issued 454,456 Class A common units to Lonestar on December 27,
2012. The aggregate consideration for the issuance was $10,000,012.
- •
- On February 1, 2013, we issued 2,061,472 Class C common units after a holder of our Class C common
units surrendered a unit certificate representing 2,061,472 class C common units. We reissued the units so they could be held separately by two individuals affiliated with the holder.
- •
- In March 2013, one employee of our general partner forfeited 4,000 Class B common units in connection with their
departure from the employ of our general partner.
- •
- On April 1, 2013, we issued 2,000 Class B common units after a holder of our Class B common units
surrendered a unit certificate representing 2,000 Class B common units. We reissued the units so they could be held by two individuals affiliated with the holder.
- •
- In April 2013, we issued an aggregate of 53,500 restricted Class B common units to six employees of our general
partner, subject to the terms and conditions of award agreements between us and each employee.
- •
- In connection with a funding, we issued 45,860 Class C common units to an affiliated entity on July 18,
2013. The aggregate consideration for the issuance was $1,628,030.
- •
- In connection with our election to convert all outstanding preferred units into common units, we issued 1,136,364
Class A common units to Lonestar on August 1, 2013. In connection with this issuance, Lonestar surrendered 524,746 Series A preferred units, 552,348 Series B preferred
units and 59,270 Series C preferred units to us, which we then cancelled.
- •
- In connection with a funding, we issued 42,254 Class C common units to an affiliated entity on August 13,
2013. The aggregate consideration for the issuance was $1,500,017.
- •
- In September 2013, we issued an aggregate of 15,000 restricted Class B common units to three employees of our
general partner, subject to the terms and conditions of award agreements between us and each employee.
- •
- In February and March 2014, we issued 11,948,752 and 612,182 Class A common units, respectively, to
JP Energy Development LP ("JP Development") in connection with our acquisition of certain assets and businesses sold to us by JP Development. The aggregate consideration for the issuance was
$276,362,548.
- •
- In connection with a funding by Lonestar, we issued 1,818,182 Series D preferred units to Lonestar on
March 31, 2014. The aggregate consideration for the issuance was $40,000,000.
- •
- In May 2014, we issued an aggregate of 20,000 restricted Class B common units to two employees of our general partner, subject to the terms and conditions of award agreements between us and each employee.
II-3
- •
- In September 2014, we issued an aggregate of 70,000 restricted Class B common units to two employees of our general partner, subject to the terms and conditions of award agreements between us and each employee.
The following documents are filed as exhibits to this registration statement:
| Exhibit Number |
Description | |
|---|---|---|
| 1.1** | Form of Underwriting Agreement (including form of Lock-up Agreement). | |
| 3.1** | Certificate of Limited Partnership of JP Energy Partners LP. | |
| 3.2** | Form of Third Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP (included as Appendix A to the Prospectus). | |
| 4.1** | Registration Rights Agreement dated November 27, 2012 among JP Energy Partners LP, Arkansas Terminaling and Trading Inc., Michael Coulson, Mary Ann Dawkins and White Properties II Limited Partnership. | |
| 5.1 | Opinion of Latham & Watkins LLP as to the legality of the securities being registered. | |
| 8.1 | Opinion of Latham & Watkins LLP relating to tax matters. | |
| 10.1** | Credit Agreement dated as of February 12, 2014 among JP Energy Partners LP, Bank of America, N.A.. as administrative agent and swing line lender and an L/C issuer, the other lender parties thereto, and Bank of America Merrill Lynch and BMO Harris Financing, Inc., as joint lead arrangers and joint book managers. | |
| 10.2** | Amendment No. 1 to Credit Agreement, dated as of April 30, 2014. | |
| 10.3 | Amendment No. 2 and Waiver to Credit Agreement, dated as of August 5, 2014. | |
| 10.4** | Form of JP Energy Partners LP 2014 Long-Term Incentive Plan. | |
| 10.5** | Form of Right of First Offer Agreement. | |
| 10.6** | Form of Employment Agreement of Patrick J. Welch. | |
| 10.7** | Form of Employment Agreement of Jeremiah J. Ashcroft III. | |
| 10.8** | Employment Agreement of Scott Smith. | |
| 10.9 | Amendment No. 3 and Waiver to Credit Agreement, dated as of September 19, 2014. | |
| 16.1** | Change in Certifying Accountant Letter. | |
| 21.1** | List of Subsidiaries of JP Energy Partners LP. | |
| 23.1 | Consent of PricewaterhouseCoopers LLP. | |
| 23.2 | Consent of Travis Wolff, LLP (Parnon Storage Inc.). | |
| 23.3 | Consent of Travis Wolff, LLP (Caddo Mills Pipeline Terminal of Truman Arnold Companies of Arkansas Terminaling and Trading, Inc.). | |
| 23.4 | Consent of Travis Wolff, LLP (Crude Oil Supply and Logistics Business of Parnon Gathering Inc.). | |
| 23.5 | Consent of Grant Thornton LLP (Heritage Propane Express, LLC). | |
| 23.6 | Consent of PricewaterhouseCoopers LLP (Falco Energy Transportation, LLC). | |
| 23.7 | Consent of Hein & Associates LLP (Wildcat Permian Services, LLC). | |
| 23.8 | Consent of Latham & Watkins LLP (contained in Exhibit 5.1). | |
| 23.9 | Consent of Latham & Watkins LLP (contained in Exhibit 8.1). |
II-4
| Exhibit Number |
Description | |
|---|---|---|
| 23.10** | Consent of Wood Mackenzie Limited. | |
| 23.11** | Consent of Director Nominee (T. Porter Trimble). | |
| 23.12 | Consent of Director Nominee (Norman J. Szydlowski). | |
| 24.1** | Powers of Attorney. | |
| 99.1** | Unaudited condensed consolidated financial statements of JP Energy Partners LP as of December 31, 2012 and March 31, 2013 and for the three months ended March 31, 2012 and 2013. |
- **
- Previously filed.
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. If a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that,
- (i)
- For
purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration
statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to
be part of this registration statement as of the time it was declared effective.
- (ii)
- For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with JP Energy GP II LLC, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid or accrued to JP Energy GP II LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.
II-5
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Irving, State of Texas, on September 22, 2014.
| JP Energy Partners LP | ||||
By: |
JP Energy GP II LLC, its general partner |
|||
By: |
/s/ J. PATRICK BARLEY J. Patrick Barley President and Chief Executive Officer |
|||
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
Signature
|
Title
|
Date
|
||||
|---|---|---|---|---|---|---|
| /s/ J. PATRICK BARLEY J. Patrick Barley |
Chairman, President and Chief Executive Officer (Principal Executive Officer) |
September 22, 2014 | ||||
* Patrick J. Welch |
Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) |
September 22, 2014 |
||||
* John F. Erhard |
Director |
September 22, 2014 |
||||
* Daniel R. Revers |
Director |
September 22, 2014 |
||||
* Lucius H. Taylor |
Director |
September 22, 2014 |
||||
* Greg Arnold |
Director |
September 22, 2014 |
||||
*By: |
/s/ J. PATRICK BARLEY J. Patrick Barley Attorney-in-fact |
|||||
II-6
| Exhibit Number | Description | |
|---|---|---|
| 1.1** | Form of Underwriting Agreement (including form of Lock-up Agreement). | |
| 3.1** | Certificate of Limited Partnership of JP Energy Partners LP. | |
| 3.2** | Form of Third Amended and Restated Agreement of Limited Partnership of JP Energy Partners LP (included as Appendix A to the Prospectus). | |
| 4.1** | Registration Rights Agreement dated November 27, 2012 among JP Energy Partners LP, Arkansas Terminaling and Trading Inc., Michael Coulson, Mary Ann Dawkins and White Properties II Limited Partnership. | |
| 5.1 | Opinion of Latham & Watkins LLP as to the legality of the securities being registered. | |
| 8.1 | Opinion of Latham & Watkins LLP relating to tax matters. | |
| 10.1** | Credit Agreement dated as of February 12, 2014 among JP Energy Partners LP, Bank of America, N.A.. as administrative agent and swing line lender and an L/C issuer, the other lender parties thereto, and Bank of America Merrill Lynch and BMO Harris Financing, Inc., as joint lead arrangers and joint book managers. | |
| 10.2** | Amendment No. 1 to Credit Agreement, dated as of April 30, 2014. | |
| 10.3 | Amendment No. 2 and Waiver to Credit Agreement, dated as of August 5, 2014. | |
| 10.4** | Form of JP Energy Partners LP 2014 Long-Term Incentive Plan. | |
| 10.5** | Form of Right of First Offer Agreement. | |
| 10.6** | Form of Employment Agreement of Patrick J. Welch. | |
| 10.7** | Form of Employment Agreement of Jeremiah J. Ashcroft III. | |
| 10.8** | Employment Agreement of Scott Smith. | |
| 10.9 | Amendment No. 3 and Waiver to Credit Agreement, dated as of September 19, 2014. | |
| 16.1** | Change in Certifying Accountant Letter. | |
| 21.1** | List of Subsidiaries of JP Energy Partners LP. | |
| 23.1 | Consent of PricewaterhouseCoopers LLP. | |
| 23.2 | Consent of Travis Wolff, LLP (Parnon Storage Inc.). | |
| 23.3 | Consent of Travis Wolff, LLP (Caddo Mills Pipeline Terminal of Truman Arnold Companies of Arkansas Terminaling and Trading, Inc.). | |
| 23.4 | Consent of Travis Wolff, LLP (Crude Oil Supply and Logistics Business of Parnon Gathering Inc.). | |
| 23.5 | Consent of Grant Thornton LLP (Heritage Propane Express, LLC). | |
| 23.6 | Consent of PricewaterhouseCoopers LLP (Falco Energy Transportation, LLC). | |
| 23.7 | Consent of Hein & Associates LLP (Wildcat Permian Services, LLC). | |
| 23.8 | Consent of Latham & Watkins LLP (contained in Exhibit 5.1). | |
| 23.9 | Consent of Latham & Watkins LLP (contained in Exhibit 8.1). | |
| 23.10** | Consent of Wood Mackenzie Limited. | |
| 23.11** | Consent of Director Nominee (T. Porter Trimble). | |
| 23.12 | Consent of Director Nominee (Norman J. Szydlowski). | |
| 24.1** | Powers of Attorney. | |
| 99.1** | Unaudited condensed consolidated financial statements of JP Energy Partners LP as of December 31, 2012 and March 31, 2013 and for the three months ended March 31, 2012 and 2013. |
- **
- Previously filed.