UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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Form 10-Q

 

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

 

OR

 

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from   to

 

Commission file number 001-36647

 

 

 

JP ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

600 East Las Colinas Blvd
Suite 2000

Irving, Texas 75039
(Address of principal executive offices) (Zip Code)

 

(Registrant’s telephone number, including area code):  (972) 444-0300

 

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES ☒   NO ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES ☒   NO ☐

 

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.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐   NO ☒

 

At August 7, 2015, there were 18,467,228 common units and 18,148,898 subordinated units outstanding. 

 

 

 

 

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TABLE OF CONTENTS

 

 

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PART IFINANCIAL INFORMATION

 

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q (this “report” or this “Form 10-Q”) 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, CB Capital Holdings II, LLC and the Greg Alan Arnold Separate Property Trust, 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.

 

Forward-Looking Statements

 

Certain statements and information in this Form 10-Q may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

 

the price of, and the demand for, crude oil, refined products and natural gas liquids (“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;

 

regulatory action affecting our existing contracts, our operating costs or our operating flexibility;

 

failure to secure or maintain contracts with our largest customers, or non-performance of any of those customers under the applicable contract;

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competitive conditions in our industry;

 

changes in the long-term supply of and demand for oil and natural gas;

 

the availability and cost of capital and our ability to access certain capital sources;

 

a deterioration of the credit and capital markets;

 

volatility of fuel prices;

 

actions taken by our customers, competitors and third-party operators;

 

our ability to complete growth projects on time and on budget;

 

inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;

 

environmental hazards;

 

industrial accidents;

 

changes in laws and regulations (or the interpretation thereof) related to the transportation, storage or terminaling of crude oil and refined products or the distribution and sales of NGLs;

 

fires, explosions or other accidents;

 

the effects of future litigation; and

 

other factors discussed elsewhere in this Form 10-Q.

 

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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Item 1.Financial Statements

 

 

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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. All references to the “Partnership”, “JPE”, “us”, “we”, “our”, and all similar expressions are references to JP Energy Partners LP and our consolidated, wholly owned subsidiaries, unless otherwise expressly stated or the context requires otherwise.  We were formed in May 2010 by members of management and were further capitalized by ArcLight Capital Partners, LLC (“ArcLight”) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our 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 our  general partner.

 

Initial Public Offering.  On October 7, 2014, we completed our initial public offering (“IPO”) of 13,750,000 common units representing a 37.7% limited partner interest in us.    In connection with the IPO, we entered into a Third Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) on October 7, 2014. The Amended 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 (as defined in our Amended Partnership Agreement) to unitholders of record on the applicable record date, subject to certain terms and conditions.

 

Common Control Acquisition between JPE and 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. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, we acquired certain midstream assets (the “Dropdown Assets”) from JP Development for an aggregate purchase price of approximately $319.1 million (the “Common Control Acquisition”), which was comprised of 12,561,934 JPE Class A Common Units and $52.0 million in cash. We financed the cash portion of the purchase price through borrowings under our revolving credit facility.  The total purchase price for 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 acquired of $12.7 million was considered a deemed distribution by our general partner.

 

Basis of Presentation.  Because JPE and JP Development are under common control, we are required under generally accepted accounting principles in the United States (“GAAP”) to account for the Common Control Acquisition in a manner similar to the pooling of interests method of accounting. Under this method of accounting, our balance sheet reflects JP Development’s historical carryover net basis in the Dropdown Assets instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. We also retrospectively recast 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). Our 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, which include the Dropdown Assets, do not fully reflect what our balance sheet, 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 our balance sheet, results of operations and cash flows will be in the future.

 

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JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from or 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 or deemed distributions to JP Development for the six months ended June 30, 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 us from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of the Common Control Acquisition.

 

The results of operations for the three and six months ended June 30, 2015 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 statement of the financial position and results of operations for such interim periods in accordance with GAAP. Although we believe the disclosures in these financial statements are adequate to 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 our audited consolidated financial statements and the related notes for the year ended December 31, 2014 included in our Annual Report on Form 10-K filed with the SEC on March 11, 2015.

 

2. Summary of Significant Accounting Policies

 

Principles of Consolidation. Our unaudited condensed consolidated financial statements 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.

 

Reclassification.  Certain previously reported amounts have been reclassified to conform to the current year presentation. For the three and six months ended June 30, 2014, we reclassified $2,441,000 and $4,591,000, respectively, from gathering, transportation and storage fees to crude oil sales to conform to the current year presentation.

 

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.  We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. We determine 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 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 our 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 fair value of our

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contingent liabilities (see Note 5) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). We do not have any other assets or liabilities measured at fair value on a recurring basis.

 

Our 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 us for debt with the same remaining maturities.

 

Restricted Cash. Restricted cash consists of cash balances that are restricted as to withdrawal or usage and include cash to secure crude oil production taxes payable to the applicable taxing authorities.

 

Accounts Receivable.  Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering 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 condensed consolidated statements of operations. The allowance for doubtful accounts was $1,580,000 and $1,134,000 as of June 30, 2015 and December 31, 2014, respectively.

 

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 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. Crude oil sales revenues are generated through outright purchase and sale contracts as well as crude oil pipeline transportation arrangements. 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. Our crude oil pipeline transportation arrangements are structured such that we purchase crude oil from a producer or supplier at a designated receipt point at an index price less a transportation fee, and sell at a designated delivery point, thereby locking in an amount that is, in effect, economically equivalent to a transportation fee. Any transportation costs we incur are included in the price of the product sold to customers, and are included within crude oil sales revenues and cost of sales, excluding depreciation and amortization. For our crude oil pipeline transportation arrangements, we enter into purchase and sale contracts with the same counterparty or different counterparties. In each case, we assess the indicators associated with agent and principal considerations for the arrangement to determine whether revenue should be recorded on a gross basis versus net basis.

 

Crude Oil Supply and Logistics. The crude oil supply and logistics segment mainly generates revenues through crude oil sales. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts 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 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, we also provide crude oil transportation services to third party customers.

 

Refined Products Terminals and Storage. We generate 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. Such fee-based revenues are recognized when services are provided upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

 

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NGL Distribution and Sales. Revenues from the NGL distribution and sales segment are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees.

 

Comprehensive Loss. For the three and six months ended June 30, 2015 and 2014, comprehensive loss was equal to net loss.

 

Recent Accounting Pronouncements.

 

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. ASU 2015-11 changes the measurement principle for inventory measured using any method other than LIFO or the retail inventory method from the lower of cost or market to lower of cost and net realizable value.  Net realizable value is defined as estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  ASU 2015-11 is effective for interim and annual periods beginning after December 15, 2016.  Early adoption of this ASU is permitted.  We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

 

In April 2015, the FASB issued ASU No. 2015-06, Earnings per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  ASU 2015-06 provides guidance on calculating and reporting historical earnings per unit under the two-class method following dropdown transactions between entities under common control. Under ASU 2015-06, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Additionally, the previously reported earnings per unit of the limited partners for periods before the date of the dropdown transaction would not change as a result of the dropdown transaction. ASU 2015-06 is effective for interim and annual periods beginning after December 15, 2015, and should be applied retrospectively for all financial statements presented. Early adoption of this ASU is permitted. We adopted ASU 2015-06 in the second quarter of 2015 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

 

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Cost. ASU 2015-03 changes the requirements for presenting debt issuance costs and requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment. ASU 2015-03 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. We plan to adopt ASU 2015-03 in the third quarter of 2015 and do not anticipate a material impact on our consolidated financial statements and related disclosures.

 

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 provides amended guidance on the consolidation evaluation for reporting entities that are required to evaluate whether they should consolidate certain legal entities, including limited partnerships. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-02 is not expected to have a material impact on our consolidated financial statements and related disclosures.

 

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable the performance target will be achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our consolidated financial statements and related disclosures.

 

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In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 supersedes the existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). In July 2015, the FASB decided to defer for one year the effective date of ASU 2014-09 for public and non-public entities reporting under U.S. GAAP. The FASB also decided to permit entities to early adopt the standard but adoption is not permitted earlier than the original effective date for public entities. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

 

3. Discontinued Operations

 

On June 30, 2014, we entered into and simultaneously closed an asset purchase agreement pursuant to which we sold all of our trucking and related assets and activities in North Dakota, Montana and Wyoming (the “Bakken Business”) for a purchase price of $9,100,000.

 

The results of operations for the Bakken Business are presented as discontinued operations for all periods in the condensed consolidated statements of operations. Prior to the classification as discontinued operations, we reported the Bakken Business in our crude oil supply and logistics segment. The following table summarizes selected financial information related to the Bakken Business’s operations for the three and six months ended June 30, 2014.

 

 

 

4. Net Income per Unit

 

Net income per unit applicable to limited partner common units and to limited partner subordinated units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO by the weighted-average number of common units and subordinated units outstanding for the period. Income 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. Diluted net income per unit includes the effects of potentially dilutive units on our common units, consisting of unvested phantom units. Basic and diluted net income per unit applicable to limited partners holding subordinated units are the same because there are no potentially dilutive subordinated units outstanding.  For the three and six months ended June 30, 2015, dilutive loss per unit was equal to basic loss per unit because all instruments were antidilutive.

 

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On July 28, 2015, the Board of Directors of our general partner declared a cash distribution for the second quarter of 2015 of $0.325 per common unit and subordinated unit. The distribution will be paid on August 14, 2015 to unitholders of record as of August 7, 2015.

 

 

 

 

 

 

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:

 

 

 

5. Acquisitions

 

Acquisition of Southern Propane Inc. On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company. The acquisition expanded the asset base and market share of our NGL distribution and sales segment, specifically the acceleration of our entry into the Houston, Texas market as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16,261,000 consisted of a $12,475,000 cash payment that was paid on the acquisition date, which was funded through the use of borrowings from our revolving credit facility, an $86,000 payable to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3,442,000 and a contingent earn-out liability with a value of $258,000 that is subject to the achievement of certain gross profit targets at Southern.  The earn-out period covers the period from June 2015 through December 2016, and the maximum earn-out that could be

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earned is $1,250,000. The common units issued with this acquisition were issued in a private offering conducted in accordance with the exemption from the registration requirements of Section 4(a)(2) of the Securities Act of 1933, as amended, as such units were issued to the owners of a business acquired in a privately negotiated transaction not involving any public offering or solicitation.

 

The fair value of the contingent earn-out liability 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 following table represents our preliminary allocation of the total purchase price of this acquisition to the assets acquired (in thousands):

 

 

 

Goodwill associated with the Southern acquisition principally results from synergies expected from integrated operations. 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 12 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.

 

Revenues attributable to Southern included in the condensed consolidated statements of operations totaled $946,000 for the period from May 8, 2015 to June 30, 2015. We do not account for the operations of Southern on a stand-alone basis, therefore, it is impracticable to report the amounts of net income of Southern included in the condensed consolidated statements of operations related to the post acquisition periods.

 

6. Inventory

 

 

Inventory consists of the following as of June 30, 2015 and December 31, 2014:

 

 

 

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7. Long-Term Debt

 

Long-term debt consists of the following at June 30, 2015 and December 31, 2014:

 

 

 

Bank of America Credit Agreement.  We have a $275,000,000 revolving loan with Bank of America, N.A. (the “BOA Credit Agreement”) that matures on February 12, 2019. As of June 30, 2015, the unused balance of the BOA Credit Agreement was $114,035,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $30,965,000 at June 30, 2015. The BOA Credit Agreement contains various restrictive covenants and compliance requirements.  We were in compliance with all covenants as of June 30, 2015.

 

8. Derivative Instruments

 

We are exposed to certain market risks related to the volatility of commodity prices and changes in interest rates.  To monitor and manage these market risks, we have established comprehensive risk management policies and procedures. We do not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. That is, we do not speculate using derivative instruments.

 

Commodity Price Risk. Our normal business activities expose us to risks associated with changes in the market price of crude oil and propane, among other commodities. Management believes it is prudent to limit our exposure to these risks, which include our (i) propane purchases, (ii) pre-existing or anticipated physical crude oil sales and (iii) certain crude oil held in inventory.  To meet this objective, we use a combination of fixed price swap and forward contracts.  Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered.  While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.  The following table summarizes the net notional volume buy/(sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the NPNS exception as of June 30, 2015 and December 31, 2014, none of which were designated as hedges for accounting purposes.

 

 

Interest Rate Risk. We are exposed to variable interest rate risk as a result of variable-rate borrowings under our revolving credit facilities. We entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of our 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, we receive variable interest rate payments and make fixed interest rate payments, thereby creating the equivalent of

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fixed-rate debt for the portion of the debt that is swapped.  As of June 30, 2015 and December 31, 2014, our outstanding interest rate swap contracts contained a notional amount of $75,000,000, with maturity dates ranging from July 2015 through September 2015.

 

Credit Risk. By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we are exposed 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 us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with high quality counterparties. We have entered into master netting agreements, including Master International Swap Dealers Association (“ISDA”) Agreements, which allow for netting of contract receivables and payables in the event of default by either party.

 

Fair Value of Derivative Instruments. We measure 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 primarily utilize level 2 inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of our derivative contracts are designated as hedging instruments. The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014 on a gross basis without regard to same-counterparty netting.

 

 

 

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheet as of June 30, 2015 that are subject to enforceable master netting arrangements.

 

 

 

As of December 31, 2014, the fair value of our recognized current and non-current derivative assets and liabilities presented on a gross basis equaled the presentation on a net basis. 

 

The following table summarizes the amounts recognized with respect to our derivative instruments within the condensed consolidated statements of operations. None of our derivatives are designated as hedges for accounting purposes.

 

 

 

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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.

 

9. Partners’ Capital and Distributions

 

Distributions. Our Amended Partnership Agreement requires that within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, subject to certain terms and conditions. The following table shows the distributions declared by us subsequent to December 31, 2014:

 

 

 

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10. Unit-Based Compensation

 

Long-Term Incentive Plan and Phantom Units.  The 2014 Long-Term Incentive Plan (“LTIP”) for our employees, directors and consultants authorizes grants of up to 3,642,700 common units in the aggregate.  Our phantom units issued under our LTIP are primarily composed of two types of grants (1) service condition grants with vesting over three years in equal annual installments; and (2) service condition grants with cliff vesting on April 1, 2018.  Distributions related to these unvested phantom units will be paid concurrent with our distribution for common units.

 

The following table presents phantom units activity for the six months ended June 30, 2015:

We expect to recognize $3.2 million of compensation expense related to non-vested phantom units over a weighted average period of 1.8 years.

 

Restricted (Non-Vested) Common and Subordinated Units.  All of our restricted Class B common units were granted prior to our IPO in October 2014, and were converted into restricted common units and restricted subordinated units upon the IPO at certain conversion ratios. 

 

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The following table presents restricted (non-vested) common and subordinated units activity for the six months ended June 30, 2015:

 

 

Pursuant to certain employment agreements, as amended, between us and certain employees, we were 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 that could have been issued pursuant to these employment agreements, as amended, was 100,000 units. As of December 31, 2014, 75,000 restricted Class B common units were issued as a result of the employees’ achievement of certain milestones and the unit-based compensation expense related to these units have been fully recorded as general and administrative expenses in respective historical periods.  With respect to the remaining 25,000 restricted Class B common units to be issued, we estimated the probable number of years for the performance goals to be achieved and have recognized the related unit-based compensation expense over the estimated number of years.  During the second quarter of 2015, each employee terminated his employment with us prior to one employee achieving his performance goal related to the remaining 25,000 restricted Class B common units.  As a result, we reversed previously recognized unit-based compensation expense of $297,000.

 

We expect to recognize $1.4 million of compensation expense related to restricted (non-vested) common and subordinated units over a weighted average period of 1.4 years.

 

Total unit-based compensation expenses related to our phantom units and restricted (non-vested) common and subordinated units were $121,000 and $302,000 for the three months ended June 30, 2015 and 2014, respectively, and $552,000 and $584,000 for the six months ended June 30, 2015 and 2014, respectively.

 

11. Commitments and Contingencies

 

Legal Matters. We are 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 our condensed consolidated financial position, results of operations or liquidity.

 

Environmental Matters. We are 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. We have established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

 

We account for environmental contingencies in accordance with 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 June 30, 2015 and December 31, 2014, we had no material environmental liabilities.

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12. Reportable Segments

 

Our 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 consisting of approximately 96 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 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 110,000 barrels of storage capacity. We also own 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. We conduct crude oil supply activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. We own 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. 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.

 

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 has eight loading lanes with automated truck loading equipment. The 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.  The North Little Rock terminal and the Caddo Mills terminal are primarily served by the Enterprise TE Products Pipeline Company LLC and the Explorer Pipeline, respectively.

 

NGL distribution and sales.  The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange, (ii) NGL sales 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 22,000 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the United States, we sell NGLs to retailers, wholesalers, industrial end users and commercial and residential customers. We also own 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 our reportable segments.

 

We account for intersegment revenues as if the revenues were to third parties.

 

Our chief operating decision maker evaluates the segments’ operating performance based on Adjusted EBITDA. 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.

 

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The following tables reflect certain financial data for each reportable segment for the three and six months ended June 30, 2015 and 2014.

 

 

 

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A reconciliation of total Adjusted EBITDA from reportable segments to net loss from continuing operations is included in the table below for the periods indicated.

 

 

 

Total assets for our reportable segments as of June 30, 2015 and December 31, 2014 were as follows:

 

 

 

 

13. Related Party Transactions

 

We perform certain management services for JP Development. We receive a monthly fee of $50,000 for these services which reduced the general and administrative expenses on the condensed consolidated statements of operations by $150,000 and $300,000 for each of the three and six month periods ended June 30, 2015 and 2014.

 

JP Development has a pipeline transportation business that provides crude oil pipeline transportation services to our crude oil supply and logistics segment. As a result of utilizing JP Development’s pipeline transportation services, we incurred pipeline tariff fees of $1,625,000 and $2,048,000 for the three months ended June 30, 2015 and 2014, respectively, and $3,265,000 and $4,953,000 for the six months ended June 30, 2015 and 2014, respectively, which are included in costs of sales on the condensed consolidated statements of operations. As of June 30, 2015 and December 31, 2014, we had a net receivable from JP Development of $7,738,000 and $7,968,000, respectively, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided by JP Development. We expect these amounts to be recovered during 2015.

 

On November 5, 2013, we 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%. The interest rate was 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 was payable quarterly in arrears. On March 20, 2014, we repaid this promissory note in full.

 

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As a result of the acquisition of the North Little Rock, Arkansas refined product terminal (“ATT”) in November 2012, TAC owns common and subordinated units in us. In addition, Mr. Greg Arnold, President and CEO of TAC, is one of our directors and owns a 5% equity interest in our general partner. Our refined products terminals and storage segment sold refined products to TAC during 2014. Our revenue from TAC was $1,999,000 and $8,380,000 for the three and six months ended June 30, 2014, respectively.

 

Our NGL distribution and sales segment also purchases refined products from TAC. We paid $288,000 and $474,000 during the three months ended and $514,000 and $969,000 during the six months ended June 30, 2015 and 2014, respectively, for refined product purchases from TAC, which are included in cost of sales on the condensed consolidated statements of operations.

 

We entered into transactions with CAMS Bluewire, an entity in which ArcLight holds a non-controlling interest. CAMS Bluewire provided IT support for us through April 2014. We paid $22,000 and $88,000 for the three months ended March 31, 2015 and 2014, respectively and $132,000 and $216,000 for the six months ended June 30, 2015 and 2014, 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, on the condensed consolidated statements of operations and the condensed consolidated balance sheets. There were no amounts due to CAMS Bluewire as of June 30, 2015.  The total amount due to CAMS Bluewire as of December 31, 2014 was $32,000.

 

During the third quarter of 2014, we began performing certain management services for Republic Midstream, LLC (“Republic”), an entity owned by ArcLight. We charge a monthly fee of approximately $58,000 for these services. The monthly fee reduced the general and administrative expenses on the condensed consolidated statements of operations by $175,000 and $350,000 for the three and six months ended June 30, 2015. During the second quarter of 2015, we began performing crude transportation services for Republic.  We charged $280,000 for these services which are included in gathering, transportation and storage fees on the condensed consolidated statements of operations. As of June 30, 2015 and December 31, 2014, we had a receivable balance due from Republic of $455,000 and $297,000, respectively, which is included in receivables from related parties on the condensed consolidated balance sheets.

 

In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight.  In the second quarter of 2015, ArcLight agreed to reimburse us for certain professional fees we incurred.  The total amounts paid on our behalf and agreed upon reimbursements were $1,254,000 and $2,604,000 for the three and six months ended June 30, 2015, respectively, and were treated as deemed contributions from ArcLight for the three and six months ended June 30, 2015.  

 

We do not have any employees. The employees supporting our operations are employees of our general partner, and as such, we reimburse our general partner for payroll and other payroll-related expenses we incur. As of June 30, 2015, we had a receivable from our general partner of $195,000 as a result of certain professional fees to be reimbursed from our general partner. As of December 31, 2014, we had a receivable balance due from our general partner of $2,205,000 as a result of the timing of payroll funding. Amounts from our general partner are included in receivables from related parties on the condensed consolidated balance sheets.

 

Our NGL distribution and sales segment enters into transactions with Enogex Holdings, an entity partially owned by ArcLight. Enogex Holdings is a provider of rack sales, propane and trucks. For the six months ended June 30, 2015, we paid $56,000 for propane purchases from Enogex Holdings, which is included in cost of sales on the condensed consolidated statements of operations. There were no amounts paid to Enogex Holdings during the three months ended June 30, 2014 and 2015 and the six months ended June 30, 2014.  As of June 30, 2015 and December 31, 2014, there were no amounts due to Enogex Holdings.

 

14.  Subsequent Events

 

In July 2015, we paid approximately $8,745,000 to settle all of our outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017.  As of June 30, 2015, these contracts were recorded at their fair value of $7,089,000.  The additional loss to be recorded in the third quarter of 2015 on the settlement transaction is approximately $1,656,000.  We simultaneously executed new propane financial swap contracts

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at current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

 

 

Item 2. 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 unaudited historical condensed consolidated financial statements and notes in “Item 1. Financial Statements” contained herein and our audited historical consolidated financial statements as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013, and 2012 included in our Annual Report on Form 10-K, as filed with the SEC on March 11, 2015 (our “2014 Form 10-K”). 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 as a result of various risk factors, including those that may not be in the control of management. 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 in our 2014 Form 10-K. See also “Forward-Looking Statements.”

 

General

 

We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized 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:

 

 

 

 

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. 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 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 an 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

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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 products. 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.

 

Recent Developments

 

Expansions of Silver Dollar Pipeline System

 

In February 2015, we signed a 10-year fee based gathering agreement with Discovery Natural Resources LLC (“Discovery”) to construct and operate an extension of our Silver Dollar Pipeline crude oil gathering system into the core of the Midland Basin. The agreement with Discovery is supported by a dedication of approximately 53,000 acres in Reagan, Glasscock, Sterling and Irion Counties. In addition to pipeline gathering, we also provide crude oil trucking, marketing and related services for Discovery. The gathering system extension will consist of approximately 55 miles of pipeline, extending from southern Reagan County north into Glasscock County across the Midland Basin. The project is expected to be completed in the second half of 2015.

 

In February 2015, we also commissioned a new 70,000 barrel crude oil storage tank which increased our total crude oil storage capacity on the Silver Dollar Pipeline to 110,000 barrels.

 

In April 2015, we announced that we have executed an interconnection agreement with an affiliate of Magellan Midstream Partners, L.P. (“Magellan”) to connect our Silver Dollar Pipeline System to Magellan’s Longhorn pipeline at the Barnhart Terminal in Crockett County, Texas. The interconnection provides producers with a third takeaway option from the Silver Dollar Pipeline System and direct access from the core of the Midland Basin to end markets in Houston. The connection is expected to be in service by the third quarter of 2015.

 

Acquisition of Southern Propane, Inc.

 

On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company for approximately $16.3 million. The acquisition was funded through the use of borrowings from our revolving credit facility and the issuance of approximately 267,000 of our common units. The Southern acquisition expanded the asset base and market share of our NGL distribution and sales segment, specifically the acceleration of our entry into the Houston, Texas market as well as the expansion of our industrial, non-seasonal customers.

 

 

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 adjusted gross margin.

 

Volumes and revenues

 

 

 

 

 

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 with the purchase of the product. We seek to minimize cost of sales, excluding depreciation and amortization, by attempting to acquire the products that we use in each of our segments at times and at prices that we believe 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.

 

Adjusted EBITDA and adjusted gross margin.  Our management uses Adjusted EBITDA and adjusted gross margin 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 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 gain (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).

 

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Adjusted EBITDA 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:

 

 

 

 

 

Adjusted EBITDA and adjusted gross margin are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and adjusted gross margin are net income (loss) and operating income (loss), respectively. Adjusted EBITDA and adjusted gross margin should not be considered as an alternative to net income (loss), operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and adjusted gross margin exclude some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. As a result, Adjusted EBITDA and adjusted gross margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

Set forth below are reconciliations of Adjusted EBITDA and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP.

 

 

 

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Results of Operations

 

The following table summarizes our results of operations for the periods presented.

 

 

 

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Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

 

Consolidated Results

 

 

 

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Depreciation and amortization expense. Depreciation and amortization expense for the three months ended June 30, 2015 increased to $12.1 million from $10.1 million for the three months ended June 30, 2014. The increase was primarily due to the expansions of our Silver Dollar Pipeline System in the fourth quarter of 2014. Our property, plant and equipment base increased from $232.7 million as of June 30, 2014 to $283.0 million as of June 30, 2015.

 

Interest expense. Interest expense for the three months ended June 30, 2015 decreased to $1.4 million from $2.3 million for the three months ended June 30, 2014. The decrease was primarily due to the repayment of a substantial portion of our revolving credit facility utilizing a portion of the proceeds from our initial public offering completed on October 7, 2014. Our average borrowing decreased from $205.4 million for the three months ended June 30, 2014 to $136.8 million for the three months ended June 30, 2015.

 

Loss on disposal of assets, net. Loss on disposal of assets, net for the three months ended June 30, 2015 increased to $1.3 million from $0.3 million for the three months ended June 30, 2014. The increase is primarily due to an increase in the write off of scrapped cylinder and valve assets associated with our cylinder exchange business.

 

Total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period. The sum of the total loss on commodity derivatives and net cash 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 was $0.5 million for the three months ended June 30, 2015 compared to $0.1 million for the three months ended June 30, 2014. The increase is due to the less favorable position of our crude oil and propane hedges during the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

 

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Non-cash inventory costing adjustment. We use the first-in, first-out (“FIFO”) method to calculate the cost of our crude oil inventory.  During the first quarter of 2015, we entered into several fixed price forward sale contracts that will be settled during the third and fourth quarters of this year.  We will physically hold the crude oil inventory associated with these forward sales contracts until the time of the sale.  The non-cash inventory costing adjustment reflects the difference between the actual purchase price for this crude oil inventory and the cost calculated under the FIFO method.  As a result, we have excluded the $3.9 million non-cash inventory costing adjustment in calculating Adjusted EBITDA, which will result in realization of the actual cost of this inventory in the same period when the inventory is physically sold.

 

Segment Operating Results

 

Crude Oil Pipelines and Storage

 

 

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Volumes. Crude oil pipeline throughput volumes increased to 29,541 barrels per day for the three months ended June 30, 2015 from 21,158 barrels per day for the three months ended June 30, 2014. The increase was due to the expansions of the Silver Dollar Pipeline System in the fourth quarter of 2014.

 

Adjusted gross margin. Adjusted gross margin increased to $7.3 million for the three months ended June 30, 2015 from $6.3 million for the three months ended June 30, 2014. The increase was primarily due to the increase in crude oil throughput volume ($0.6 million), which also increased crude oil sales margin ($0.4 million).

 

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Crude Oil Supply and Logistics

 

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Volumes. Crude oil sales volumes increased to 70,605 barrels per day for the three months ended June 30, 2015 from 41,476 barrels per day for the three months ended June 30, 2014. The increase was primarily due to the growth of our market share in the Permian Basin related to the expansions of the Silver Dollar Pipeline System in the fourth quarter of 2014 and new contracts signed in the first half of 2015.

 

Adjusted gross margin. Adjusted gross margin decreased to $2.2 million for the three months ended June 30,  2015 from $3.4 million for the three months ended June 30, 2014 primarily  due to a  decrease in crude oil sales margin ($2.1 million) partially offset by an increase in crude oil sales volumes ($0.9 million), as explained above. The significant increase in oil production growth in North America has generally created regional supply and demand imbalances, due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location pricing differentials. The decrease in crude oil sales margin is primarily due to the impact of the current lower-priced crude oil market on margin per barrel and the lack of any market dislocation opportunities in the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

 

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Refined Products Terminals and Storage

 

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Volumes. Volumes decreased to 61,073 barrels per day for the three months ended June 30, 2015 from 66,814 for the three months ended June 30, 2015. The decrease was primarily due to increased competition in our area of operations.

 

Revenues. Revenues decreased to $4.7 million for the three months ended June 30, 2015 from $4.9 million for the three months ended June 30, 2014. The decrease was primarily due to a decrease in refined products sales revenue of $0.3 million due to the decrease in refined product commodities prices in the three months ended June 30, 2015 compared to the three months ended June 30, 2014. This decrease was partially offset by an increase in terminal throughput and additive fees of $0.1 million related to changes in our terminaling agreements in the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

 

Cost of Sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization, increased to $1.3 million for the three months ended June 30, 2015 from $1.0 million for the three months ended June 30, 2014. The increase was primarily due to an increase in butane blending sales volumes which have a higher cost of sales as a result of profit sharing agreements.

 

Operating Expenses. Operating expenses decreased to $0.8 million for the three months ended June 30, 2015 from $3.3 million for the three months ended June 30, 2014. The decrease was primarily due to the recording of a non-recurring 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 remediated our measurement and quality control processes to be in compliance with industry standards, and we returned approximately 24,000 barrels of refined products to customers.

 

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NGL Distribution and Sales

 

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Adjusted gross margin. Adjusted gross margin increased to $22.3 million for the three months ended June 30, 2015 from $18.5 million for the three months ended June 30, 2014. The increase was primarily due to an increase in the average NGL and refined products sales margin ($1.9 million) combined with an increase in NGL and refined product sales volumes ($1.8 million). The average sales margin of NGL and refined products increased due to more favorable market conditions in the three months ended June 30, 2015 compared to the three months ended June 30, 2014. Sales volumes increased as a result of organic growth in our customer base as well as of the acquisition of Southern Propane in May 2015.

 

Operating expenses. Operating expenses increased to $14.2 million for the three months ended June 30, 2015 from $12.9 million for the three months ended June 30, 2014. The increase was primarily due to an increase in employee costs of $1.1 million related to the increased sales volumes.

 

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Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

 

Consolidated Results

 

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Depreciation and amortization expense. Depreciation and amortization expense for the six months ended June 30, 2015 increased to $23.4 million from $20.2 million for the six months ended June 30, 2014. The increase was primarily due to the expansions of our Silver Dollar Pipeline System in the fourth quarter of 2014. Our property, plant and equipment base increased from $232.7 million as of June 30, 2014 to $283.0 million as of June 30, 2015.

 

Interest expense. Interest expense for the six months ended June 30, 2015 decreased to $2.6 million from $5.6 million for the six months ended June 30, 2014. The decrease was primarily due to the repayment of a significant portion of our revolving credit facility utilizing a portion of the proceeds from our initial public offering completed on October 7, 2014. Our average borrowing decreased from $209.9 million for the six months ended June 30, 2014 to $119.9 million for the six months ended June 30, 2015.

 

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 in February 2014.

 

Loss on disposal of assets, net. Loss on disposal of assets, net for the six months ended June 30, 2015 increased to $1.4 million from $0.7 million for the six months ended June 30, 2014. The increase is primarily due to an increase 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 on commodity derivatives and net cash (receipts) payments for commodity

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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 gain on commodity derivatives was $3.5 million for the six months ended June 30, 2015 compared to a loss of $0.6 million for the six months ended June 30, 2014. The change is due to the more favorable position of our crude oil and propane hedges during the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

 

Non-cash inventory costing adjustment. We use the FIFO method to calculate the cost of our crude oil inventory.  During the first quarter of 2015, we entered into several fixed price forward sale contracts that will be executed during the third and fourth quarters of this year.  We will physically hold the crude oil inventory associated with these forward sales contracts until the time of the sale.  The non-cash inventory costing adjustment reflects the difference between the actual purchase price for this crude oil inventory and the cost calculated under the FIFO method.  As a result, we have excluded the $1.0 million non-cash inventory costing adjustment in calculating Adjusted EBITDA, which will result in realization of the actual cost of this inventory in the same period when the inventory is physically sold.

 

Transaction costs and other non-cash items. Transaction costs and other non-cash items increased for the six months ended June 30, 2015 to $2.8 million from $0.9 million for the six months end June 30, 2014 primarily due to $1.1 million of expenses related to changes in our management structure and personnel in the six months ended June 30, 2015 and an increase in transaction costs of $1.1 million. The decrease was partially offset by a decrease in non-cash vacation expenses of $0.2 million related to changes in our management structure and personnel in the six months ended June 30, 2015.

 

Segment Operating Results

 

Crude Oil Pipelines and Storage

 

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Volumes. Crude oil pipeline throughput volumes increased to 28,939 barrels per day for the six months ended June 30, 2015 from 19,652 barrels per day for the six months ended June 30, 2014. The increase was due to the expansions of the Silver Dollar Pipeline System in the fourth quarter of 2014.

 

Adjusted gross margin. Adjusted gross margin increased to $14.0 million for the six months ended June 30, 2015 from $12.4 million for the six months ended June 30, 2014. The increase was primarily due to the increase in crude oil throughput volume ($1.9 million), as explained above, partially offset by a decrease in storage fees ($0.2 million). The decrease in storage fees is due to a service outage that occurred to make repairs to a portion of our storage tanks in January 2015.

 

Crude Oil Supply and Logistics

 

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Volumes. Crude oil sales volumes increased to 72,183 barrels per day for the six months ended June 30, 2015 from 42,411 barrels per day for the six months ended June 30, 2014. The increase was primarily due to the growth of our market share in the Permian Basin related to the expansions of the Silver Dollar Pipeline System in the fourth quarter of 2014 and new contracts signed in the first half of 2015.

 

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Adjusted gross margin. Adjusted gross margin increased to $7.2 million for the six months ended June 30, 2015 from $6.5 million for the six months ended June 30, 2014 primarily due to an increase in crude oil sales volumes ($3.0 million), as explained above, partially offset by a decrease in crude oil sales margin ($2.3 million). The significant increase in oil production growth in North America has generally created regional supply and demand imbalances, due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location pricing differentials. The decrease in crude oil sales margin is primarily due to the impact of the current lower-priced crude oil market on margin per barrel and the lack of any market dislocation opportunities in the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

 

Operating expenses. Operating expenses increased to $3.9 million for the six months ended June 30, 2015 from $3.1 million for the six months ended June 30, 2014. The increase was primarily due to an increase in insurance premiums ($0.4 million) and an increase in employee expenses ($0.2 million) related to growth in our operating personnel utilized to serve our growing market share in the Permian Basin.

 

Refined Products Terminals and Storage

 

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Volumes. Volumes decreased to 62,423 barrels per day for the six months ended June 30, 2015 from 64,262 for the six months ended June 30, 2015. The decrease was primarily due to increased competition in our area of operations.

 

Revenues. Revenues decreased to $10.2 million for the six months ended June 30, 2015 from $13.9 million for the six months ended June 30, 2014. The decrease was primarily due to a decrease in refined product sales revenue of $4.4 million from a decrease in both refined product sales volumes ($3.3 million) and commodities prices ($1.1 million) in the six months ended June 30, 2015 compared to the six months ended June 30, 2014. This decrease was partially offset by an increase in terminal throughput and additive fees of $0.5 million related to changes in our terminaling agreements in the six months ended June 30, 2015 and an increase in storage fees of $0.2 million.

 

Cost of sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization, decreased to $3.2 million for the six months ended June 30, 2015 from $4.1 million for the six months ended June 30, 2014. The decrease was primarily due to the decrease in refined product commodities prices in the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

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Operating expenses. Operating expenses decreased to $1.4 million for the six months ended June 30, 2015 from $4.0 million for the six months ended June 30, 2014. The decrease was primarily due to the recording of a non-recurring 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 remediated our measurement and quality control processes to be in compliance with industry standards, and we returned approximately 24,000 barrels of refined products to customers.

 

General and administrative. General and administrative expenses decreased to $0.3 million for the six months ended June 30, 2015 from $0.7 million for the six months ended June 30, 2014. The decrease was primarily due to changes in our management structure and personnel in the six months ended June 30, 2015.

 

NGL Distribution and Sales

 

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Adjusted gross margin. Adjusted gross margin increased to $50.6 million for the six months ended June 30, 2015 from $39.9 million for the six months ended June 30, 2014. The increase was primarily due to an increase in NGL and refined product sales volumes ($6.5 million) combined with an increase in the average NGL and refined products sales margin ($4.2 million). Sales volumes increased as a result of organic growth in our customer base and the acquisition of Southern Propane in May 2015. The average sales margin of NGL and refined products increased due to more favorable market conditions in the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

 

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Operating expenses. Operating expenses increased to $27.0 million for the six months ended June 30, 2015 from $25.7 million for the six months ended June 30, 2014. The increase was primarily due an increase in employee costs of $1.1 million related to the increased sales volumes.

 

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. We expect our sources of liquidity to include cash generated from operations, 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

 

We intend to pay a minimum quarterly distribution of $0.3250 per unit per quarter, which equates to approximately $12.0 million per quarter, or $48.0 million per year, calculated based on the number of common and subordinated units outstanding as of August 7, 2015 and estimated unvested phantom units under our long-term incentive plan. We do not have a legal obligation to pay this distribution, except as provided in our partnership agreement. We currently estimate that our distributable cash flow in certain quarters of 2015 will be less than our anticipated distributions to unitholders during those periods. This shortfall is expected to be temporary and will be funded with borrowings from our revolving credit facility. The amount of such borrowings is currently estimated to be in a range of $5.0 to $11.0 million. A distribution of $0.3250 per common unit and subordinated unit for the three months ended June 30, 2015 was declared on July 28, 2015 and will be paid on August 14, 2015 to unitholders of record as of August 7, 2015.

 

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 allows 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, among other things, refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and for general partnership purposes, including distributions, so long as the use is 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;

 

                                          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 net total leverage ratio is subject to a provision for increases up to 5.00 in connection with certain future acquisitions and from and after our issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 5.00, which requirement to maintain a certain consolidated net total ratio is subject to increase up to 5.50 in connection with certain future acquisitions; and

 

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                                          from and after our issuance of certain unsecured notes, a consolidated senior secured net leverage ratio of not more than 3.50.

 

We were in compliance with all covenants under our revolving credit facility as of June 30, 2015.

 

As of July 31, 2015, we had $143.0 million of outstanding borrowings under our revolving credit facility and a remaining borrowing capacity of $101.2 million thereunder. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $30.8 million as of July 31, 2015.

 

Borrowings under our revolving credit facility 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 (base rate, LIBOR and applicable margin each as defined in our revolving credit facility). As of June 30, 2015, the applicable margin for base rate loans under our revolving credit facility range from 0.75% to 2.00% 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.

 

Cash Flow

 

Cash provided by (used in) operating activities, investing activities and financing activities were as follows for the periods indicated:

 

 

 

Cash provided by operating activities.    Cash provided by operating activities was $19.3 million for the six months ended June 30, 2015 compared to $7.6 million for the six months ended June 30, 2014. The $11.7 million increase was primarily attributable to a $30.7 million increase from the timing of collections and payments, combined with a $10.2 million increase in total Adjusted EBITDA. These amounts were partially offset by an increase of $28.3 million in cash used for inventory, primarily related to the timing of our crude oil purchases.

 

Cash used in investing activities.    Cash used in investing activities was $43.7 million for the six months ended June 30, 2015 compared to $4.9 million for the six months ended June 30, 2014. The $38.8 million increase was primarily due to an increase in capital expenditures of $17.4 million in the six months ended June 30, 2014 associated with our organic growth projects and $12.5 million related to the acquisition of Southern Propane in 2015, partially offset by a $9.5 million decrease in proceeds from the sale of assets.

 

Cash provided by (used in) financing activities.    Cash provided by financing activities was $23.5 million for the six months ended June 30, 2015 compared to cash used of $4.7 million for the six months ended June 30, 2014. For the six months ended June 30, 2015, cash provided by financing activities included net borrowings under our revolving credit facility and other debt of $47.0 million, partially offset by distributions to unitholders of $23.0 million. For the six months ended June 30, 2014, cash used in financing activities included $52.0 million used to purchase the Dropdown Assets, partially offset by $48.0 million of cash provided by the issuance of common and preferred units.

 

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.

 

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Capital Expenditures

 

Our capital spending program is focused on expanding our pipeline and cylinder exchange businesses, 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.

 

Under our partnership agreement, maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while growth 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, growth 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.

 

Our capital expenditures were $44.7 million for the six months ended June 30, 2015, which included capital expenditures for acquisitions of $12.5 million. As of June 30, 2015, we have spent approximately $32.2 million on capital expenditures, excluding acquisitions, of which $2.7 million represents maintenance capital expenditures and $29.5 million represents growth capital expenditures. We expect growth capital expenditures for the year ending December 31, 2015 to range from $75.0 million to $100.0 million, with the substantial majority of these investments to be made on our Silver Dollar Pipeline system. This estimated range of growth capital expenditures does not include any potential third party acquisitions that we will continue to evaluate throughout 2015.

 

Although we intend to move forward with our planned internal growth projects, we may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our expansion activities. We expect to fund our growth capital expenditures with borrowings under our revolving credit facility and a combination of debt and equity issuances.

 

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 $26.4 million and $26.3 million as of June 30, 2015, and December 31, 2014, respectively.

 

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 the availability of financing under our revolving credit facility could impact our ability to fund our working capital requirements for liquidity and capital resources.

 

Off-Balance Sheet Arrangements

 

We have not entered into any transactions, agreements or other contractual arrangements that would result in off balance sheet liabilities.

 

Critical Accounting Policies and Estimates

 

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2014 Form 10-K for the year ended December 31, 2014 and have not changed.

 

 

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Item 3. Quantitative and Qualitative 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. See note 8 to our condensed consolidated financial statements included in Part I, Item I of this Form 10-Q for additional information.

 

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. During the six months ended June 30, 2015, we also entered into fixed price forward sales contracts related to certain barrels of oil held in inventory and fixed price swap contracts to manage commodity price risk on anticipated physical crude oil sales.  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 fixed price forward contracts and swap contracts. 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

 

Sensitivity analysis. The table below summarizes our commodity-related financial derivative instruments and fair values, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity.

 

 

 

Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income. The preceding hypothetical analysis is limited because changes in prices may or may not equal 10% and actual results may differ.

 

In July 2015, we paid approximately $8,745,000 to settle all of our outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017.  As of June 30, 2015, these contracts were recorded at their fair value of $7,089,000.  The additional loss to be recorded in the third quarter of 2015 on the settlement transaction is approximately $1,656,000.  We simultaneously executed new propane financial swap contracts at current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

 

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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. As of June 30, 2015, $75.0 million of our outstanding debt is economically hedged, specifically $32.0 million through July 2015 with an interest rate of 0.54% plus an applicable margin and $43.0 million through September 2015 with an interest rate of 0.51% plus an applicable margin. Based on our overall interest rate exposure to variable rate debt outstanding as of June 30, 2015, a 1% increase or decrease in interest rates would change interest expense by approximately $0.6 million.

 

We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

 

Credit risk. We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through analyzing the counterparties’ financial condition prior to entering into an agreement, establishing credit limits, monitoring the appropriateness of these limits on an ongoing basis and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support.

 

Item 4.Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

An evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of June 30, 2015. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of June 30, 2015, our disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures because of the material weaknesses in our internal control over financial reporting discussed below.

 

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 and restatements of our financial statements in the periods prior to 2014. Additionally, these material weaknesses could result in a misstatement of the account balances or disclosures that would result in material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

 

We have made significant progress towards remediating the material weaknesses in our internal control over financial reporting and are implementing additional processes and controls designed to address the underlying causes of

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the material weaknesses. During the course of implementing additional processes and controls, as well as controls operating effectiveness testing, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address material weaknesses or determine to modify certain of the remediation measures. The effectiveness of our remediation will be tested by both management and our external auditors at the end of 2015.

 

Changes in Internal Controls over Financial Reporting

 

Except for the remediation efforts described above, there was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

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PART II — OTHER INFORMATION

 

Item 1.Legal Proceedings.

 

The information required for this item is provided in Note 11 — Commitments and Contingencies, included in the unaudited notes to our condensed consolidated financial statements included under Part I, Item I of this Form 10-Q, which is incorporated herein by reference.

 

Item 1A. Risk Factors.

 

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors under Item 1A of our annual report on Form 10-K for the year ended December 31, 2014. There has been no material change in our risk factors from those described in our 2014 Form 10-K. Such risks are not the only risks we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also have a material adverse effect on our business or our operations.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

The information required for this item is provided in Note 5 —  Acquisitions, included in the unaudited notes to our condensed consolidated financial statements included under Part I, Item I of this Form 10-Q, which is incorporated herein by reference.  

 

 

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Item 6. Exhibits.

 

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*Previously filed

**Filed herewith

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

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