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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

or

o         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, including zip code)

(972) 444-0300

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o  No x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o  No x

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 x  No o

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 x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 Exchange Act).  Yes o  No x

As of June 30, 2014 the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on October 2, 2014.

As of March 2, 2015, the Registrant had 18,200,121 common units and 18,158,903 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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PART I

Unless the context otherwise requires, references in this Annual Report on Form 10-K (this “report” or this “Form 10-K”) 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.

Cautionary Note Regarding Forward-Looking Statements

Certain statements and information in this Annual Report on Form 10-K 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;

·                                          competitive conditions in our industry;

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

·                                          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;

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·                                          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 Annual Report.

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.

ITEM 1. BUSINESS

Overview

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:

·                  owning, operating and developing midstream assets serving two of the most prolific shale plays in the United States, as well as serving key crude oil, refined product and NGL distribution hubs;

·                  providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and

·                  operating one of the largest portable propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.

We are focused on growing our business through organic development, acquiring and constructing additional midstream infrastructure assets and increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs. Our crude oil businesses are situated in high growth areas, including the Permian Basin, Mid-Continent and Eagle Ford shale, and provide us with a footprint to increase our volumes as these areas experience further drilling and production growth. In addition, we believe we have a competitive advantage with regard to the sourcing of opportunities to build, own and operate additional crude oil pipelines due to the insights in the market that we obtain while providing services to customers in our crude oil supply and logistics segment. We believe that our NGL distribution and sales segment will continue to grow due to our recent expansion into new geographic markets, an increased market presence in our existing areas of operation and the increase in industrial and commercial applications for NGLs such as in oilfield and agricultural services.

For additional information relating to our disclosure of revenues, profits and total assets by operating segment, please read “Note 16—Reportable Segments” included in our audited consolidated financial statements incorporated by reference into this Form 10-K.

Our Acquisition History

Since our formation and the formation of our affiliate, JP Energy Development LP (“JP Development”), in July 2012, our management team has successfully established a strategic midstream platform through us and JP Development by way of 25 third-party acquisitions and numerous organic capital projects. These include the acquisitions of:

·      the Silver Dollar Pipeline System in October 2013;

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·                  our NGL transportation business in October 2013, consisting of approximately 43 hard shell tank trucks;

·                  our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012;

·                  our crude oil storage facility in Cushing, Oklahoma in August 2012;

·                  our initial crude oil gathering and transportation operations, consisting of approximately 69 crude oil gathering and transportation trucks and our proprietary CAST software, in July 2012;

·                  our cylinder exchange business in June 2012; and

·                  17 separate wholesale and retail propane businesses from July 2010 through July 2013.

How We Conduct Our Business

We conduct our business through fee-based and margin-based arrangements.

Fee-based.  We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide within our NGL distribution and sales segment. In our crude oil pipelines business, we purchase crude oil at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price. We consider this a fee-based business because we lock in the economic equivalent of a transportation fee. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from one month to nine 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 blending services in our crude oil supply and logistics segment and our refined products terminals and storage segment, which allows us to generate additional margin based on the difference between our cost to purchase and blend the products and the market sales price of the finished blended product. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.

Our Relationship With JP Development and ArcLight

Our affiliate, JP Development, is a growth-oriented limited partnership that was formed in July 2012 by members of our management team and ArcLight for the express purpose of supporting our growth. JP Development intends to acquire growth-oriented midstream assets and to develop organic capital projects and then offer those assets for sale to us after they have been sufficiently developed such that their financial profile is suitable for us.

Since its formation, our management team and ArcLight have successfully grown JP Development through the acquisition of midstream assets and the execution of growth projects strategically located in our current areas of operation as well as new areas for expansion. In February 2014, we acquired from JP Development an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets for aggregate consideration valued at approximately $319.1 million. We refer to this transaction as the JP Development Dropdown. Please read “—JP Development Dropdown.”

We believe that ArcLight Fund V’s and our management’s collective ownership of (i) 95% of our general partner, which owns all of our incentive distribution rights, (ii) a 56.1% limited partner interest in us and (iii) 100% of the partnership interests in JP Development create a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business. We believe that our relationship with JP Development and ArcLight will provide us with future growth opportunities, including the potential acquisition of the ROFO Assets (as defined below).

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Right of First Offer

JP Development has granted us a right of first offer on all of its current and future assets, and ArcLight Fund V has granted us a right of first offer with respect to a 50% indirect interest in Republic Midstream, LLC (“Republic”), an ArcLight portfolio company. The right of first offer with respect to JP Development’s current and future assets is for a period of five years from the closing of our initial public offering (“IPO”) and the right of first offer with respect to Republic is for a period of eighteen months from the closing of our IPO. A description of JP Development’s current assets and Republic, which we collectively refer to as the ROFO Assets, is provided below.

·                  Great Salt Plains Pipeline.  An approximately 115-mile intrastate crude oil pipeline that runs from Cherokee, Oklahoma to Cushing, Oklahoma that was placed in service in October 2012. The Great Salt Plains Pipeline has a current capacity of approximately 27,000 barrels per day (“bpd”) and JP Development has the capability to install two pump stations that will expand its capacity to in excess of 40,000 bpd. The Great Salt Plains Pipeline serves the Mississippian Lime play and connects to (i) crude oil storage tanks owned by JP Development in Cherokee, Oklahoma with a shell capacity of approximately 170,000 barrels and (ii) leased crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels leased by us pursuant to a long-term lease with a third party.

·                  Red River Pipeline.  An approximately 75-mile interstate crude oil pipeline serving the Fort Worth Basin that originates in Grayson County, Texas and runs to its principal terminus at the Elmore City Station in Garvin County, Oklahoma. The Red River Pipeline has a current capacity of approximately 5,000 bpd.

·                  Republic Midstream.  A 100% member interest in Republic Midstream Gathering II, LLC, which owns a 50% indirect interest in Republic. Republic has agreed to build, own and operate certain crude oil midstream assets for Penn Virginia Corp. in the Eagle Ford shale region. Republic’s initial assets will consist of a 180-mile crude oil gathering system in Gonzales and Lavaca Counties that will deliver the gathered volumes to a 144-acre central delivery terminal in Lavaca County that is capable of storing and blending crude oil volumes. Republic is also constructing a 12-inch, 30-mile takeaway pipeline from the central delivery terminal. Subject to entering into definitive documentation, we have agreed to perform certain commercial services for Republic, including working with producers to transport crude oil from the wellhead to end markets.

JP Development Dropdown

In February 2014, we acquired the following assets in the JP Development Dropdown in exchange for consideration valued at approximately $319.1 million:

·                  Silver Dollar Pipeline System.  The Silver Dollar Pipeline System is a long-term contracted crude oil pipeline system consisting of approximately 94 miles of high-pressure steel pipeline in the Spraberry, Wolfberry and Wolfcamp plays within Crockett, Reagan and Irion counties in Texas, with throughput capacity of 130,000 bpd, truck terminals and truck injection stations, multiple receipt points and 40,000 barrels of crude oil storage.

·                  Crude oil supply and logistics assets.  A portfolio of crude oil assets consisting of approximately 70 crude oil gathering and transportation trucks and approximately 30 truck injection stations that provide our customers with multiple outlets within a market.

·                  Natural gas liquids assets.  Approximately 43 hard shell tank trucks engaged in the transportation of NGLs and condensate, including Y-grade, propane, butane and other NGLs, in the Eagle Ford shale and the Permian.

Our Assets and Operations

Crude Oil Pipelines and Storage

Crude Oil Pipelines

Silver Dollar Pipeline System.  The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Spraberry, Wolfberry and Wolfcamp plays in the Midland Basin. The system currently consists of approximately 94 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 barrels per day and two interconnections to third-party long-haul transportation pipelines. Our operations are underpinned by long-term, fee-based contracts with leading producers in the Midland Basin. One significant contract has a remaining term of approximately nine years and contains an acreage dedication related to crude oil production from approximately 110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately

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five years and contains a minimum volume commitment that was amended in March 2014 and again in September and November 2014 to significantly increase the volumes committed thereunder. A third significant contract has a remaining term of approximately 10 years and contains an acreage dedication related to crude oil production from approximately 53,000 acres in Reagan, Glasscock, Sterling and Irion Counties.

The Silver Dollar Pipeline System is located in the Spraberry, Wolfberry and Wolfcamp plays in the Midland Basin within Crockett, Reagan and Irion Counties, Texas, liquids-rich plays being developed by several large oil and gas producers. The Spraberry, Wolfberry and Wolfcamp are stacked plays with multiple horizontal targets that can be accessed with a single well. As of December 2014, the Silver Dollar Pipeline System is connected to producers that control approximately 321,000 acres in Crockett, Reagan, Irion and Schleicher Counties, Texas, and we are in advanced negotiations with other producers in the area to connect substantial additional acreage to the system and contract for additional minimum volume commitments or acreage dedications. The table below contains operational information related to the Silver Dollar Pipeline System.

Construction of the Silver Dollar Pipeline System began in October 2012, and it was put into service in April 2013. The pipeline extends from the Midway Station in Crockett County, Texas to the Owens Station in Reagan County, Texas, a 4.3-acre site with an interconnection to Plains All American Pipeline, L.P.’s Spraberry Expansion. The Midway Station is strategically located in the heart of the Southern Wolfcamp. It receives trucking volumes from multiple producers located to the south and has connections to neighboring producer facilities. The Midway Station currently has a 10,000 barrel tank and seven truck injection stations.

During the third quarter of 2014, we completed expansions of our Silver Dollar Pipeline System located in the Permian Basin. These expansions added an incremental 36 miles to the existing pipeline system, resulting in a total length of approximately 94 miles. As a result of these expansion projects, we amended an existing contract with one of our major customers, which increased the minimum volume commitment thereunder and extended the contract term by five years. In addition, the throughput capacity of our Silver Dollar Pipeline System increased by 30,000 barrels per day.

In our crude oil pipelines business, we purchase crude oil from a producer or supplier at a designated receipt point on our Silver Dollar Pipeline System at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, allowing us to lock in a fixed margin that

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is in effect economically equivalent to a transportation fee. These transactions account for substantially all of the Adjusted EBITDA we generate on our Silver Dollar Pipeline System.

Crude Oil Storage

We own a crude oil storage facility in Cushing, Oklahoma with an aggregate shell capacity of approximately 3.0 million barrels, consisting of five 600,000-barrel storage tanks. These storage tanks were built in 2009 and are located on the western side of a terminal owned by Enterprise Products Partners L.P. (the “Enterprise Terminal”). The storage tanks are able to receive approximately 22,000 barrels of crude oil per hour or deliver approximately 8,000 barrels of crude oil per hour, and have inbound connections with multiple pipelines and two-way interconnections with all of the other major storage facilities in Cushing, including the delivery point specified in all crude oil futures contracts traded on the NYMEX. TEPPCO Partners LP (“TEPPCO”), a wholly owned subsidiary of Enterprise, serves as the operator of our facilities.

Our crude oil storage business provides stable and predictable fee-based cash flows. All of the shell capacity of our storage tanks is dedicated to one customer pursuant to a long-term contract, backed by a letter of credit, with a remaining term of approximately 2.5 years as of December 31, 2014. Our customer has the option to extend this contract by two years pursuant to a renewal option. We generate crude oil storage revenues by charging this customer a fixed monthly fee per barrel of shell capacity that is not contingent on the customer’s actual usage of our storage tanks.

Our storage facility is on land that is subject to a 50-year lease with TEPPCO. We have the option to extend our lease by up to an additional 30 years. Our location in the Enterprise Terminal provides our customer with access to multiple pipelines outbound from Cushing, including a manifold connecting our tanks to the Enterprise Terminal. The Enterprise Terminal is connected to the Seaway Pipeline, which is owned and operated by Enterprise and Enbridge Inc. and transports crude oil from Cushing to the Gulf Coast.

We are party to an operating agreement pursuant to which an affiliate of TEPPCO operates and maintains the crude oil storage tanks located at our crude oil storage facility and provides us with certain services, including services related to product movements, data tracking, station operations (including documentation and inspection programs), financial and accounting matters and purchases of material. These services are provided to us at a monthly base rate and we are permitted to request additional services from TEPPCO, which are provided to us at cost. TEPPCO is obligated to perform the services as a reasonably prudent operator and in accordance with all applicable laws and accepted industry practices. The operating agreement contains certain other customary terms, including provisions relating to restrictions on assignment, terms of payment, indemnification, confidentiality and dispute resolution. The operating agreement remains in place for the same term as the lease agreement described above.

Crude Oil Supply and Logistics

Our crude oil supply and logistics segment manages the physical movement of crude oil from origination to final destination largely through our network of owned and leased assets. Our assets and operations are located in areas of substantial crude oil production growth, including the Permian Basin, Mid-Continent and Eagle Ford shale. We own and operate a fleet of approximately 135 crude oil gathering and transportation trucks and approximately 30 crude oil truck injection stations and terminals. We also lease crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels pursuant to a long-term lease with a third party. Due to the limited pipeline infrastructure in some of the basins in which we operate, our crude oil gathering and transportation trucks provide immediate access for customers to transport their crude oil to the most advantageous outlets, including pipelines, rail terminals and local refining centers.

We primarily generate revenues in our crude oil supply and logistics segment by purchasing crude oil from producers, aggregators and traders at an index price less a discount and selling crude oil to producers, traders and refiners at a price linked to the same index. The majority of activities that are carried out within our crude oil supply and logistics segment are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside opportunities. We intend to utilize our knowledge of matters related to crude oil supply and logistics to create opportunities to address the infrastructure needs of developing crude oil basins. We believe this will allow us to significantly grow our operations in the Permian Basin, Mid-Continent and Eagle Ford shale.

In general, sales prices referenced in the underlying contracts, most of which have a 30-day evergreen term, are market-based and may include pricing differentials for such factors as delivery location or crude oil quality. Our crude oil supply and logistics operations generate substantial revenues and cost of products sold as a result of the significant volume of crude oil bought and sold. While the absolute price levels of crude oil significantly impact revenues and cost of products sold,

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such price levels normally do not bear a relationship to gross profit for crude oil sales generated under buy/sell contracts. As a result, period-to-period variations in revenues and cost of products sold are not generally meaningful in analyzing the variation in gross profit for our crude oil supply operations.

We also generate revenue in this segment by performing blending services whereby we purchase varying qualities of crude oil from our producer and logistics customers, which we blend in our leased storage tanks to WTI or other specifications. The level of profit associated with our blending operations is influenced by overall contract structure and the degree of market volatility, as well as variable operating expenses. Please read “—How We Conduct Our Business” for more details on these contractual arrangements.

We mitigate the commodity price exposure of our crude oil supply and logistics operations by limiting our net open positions through the concurrent purchase and sale of like quantities of crude oil intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. All of our supply activities are subject to our comprehensive risk management policy, which establishes limits in order to manage risk and mitigate our commodity price exposure.

We are focused on increasing the utilization of our crude oil gathering and transportation fleet. We typically assign crude oil gathering and transportation trucks to a specific area but can temporarily relocate them to meet demand as needed.

CAST.  We equip our drivers with advanced computer technology and dispatch them from central locations in Perryton, Texas, San Angelo, Texas, Whitesboro, Texas, Pearsall, Texas and Pratt, Kansas. We believe that our proprietary CAST software, which is employed by our entire fleet of crude oil gathering and transportation trucks, provides us with a competitive advantage by allowing us to offer our customers a differentiated level of service. Our drivers are provided with hand-held computers which allow them to utilize our CAST software after they have loaded product. Our CAST software is a centralized system for dispatch, electronic ticket management, reporting, operations data management and lease data management. The CAST software validates ticket data in the field to greatly improve accuracy relative to paper tickets and provides our customers with near real-time views of dispatch, truck tickets, vehicle location, load acceptances and rejections and drivers. The CAST software also offers our customers flexible reporting options by providing customized data to the customer in the format that works best for its accounting and marketing needs.

Refined Products Terminals and Storage

Our refined products terminals and storage segment is comprised of two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our refined products terminals are facilities where refined products are transferred to or from storage or transportation systems, such as pipelines, to other transportation systems, such as trucks. Our refined products terminals play a key role in moving product to the end-user market by providing the following services:

·                  receipt, storage, inventory management and distribution;

·                  blending and injection of additives to achieve specified grades of gasoline; and

·                  other ancillary services that include heating of bio-diesel, product transfer and railcar handling services.

Our refined products terminals consist of multiple storage tanks with a combined aggregate storage capacity of 1.3 million barrels and are equipped with automated truck loading equipment that is operational 24 hours per day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by the terminal and our customers. In addition, our refined products terminals are equipped with truck loading racks capable of providing automated computer blending to individual customer specifications.

We generate fee-based revenues in our refined products terminals and storage segment from:

·                  throughput fees based on the receipt and redelivery of refined products, including fees based on the volume of product redelivered from the terminal;

·                  storage fees based on a rate per barrel of storage capacity per month;

·                  additive service fees based on ethanol and biodiesel used in blending services and for additive injection; and

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·                  ancillary fees for the heating of bio-diesel, product transfer and railcar handling services.

Our refined products terminals and storage segment generates its fee-based revenues pursuant to contracts that typically contain evergreen provisions consistent with industry practice so that, after an initial term of six months to two years, they can be canceled upon 60 days’ notice. We also generate revenues from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. A majority of the customers in our refined products terminals and storage segment are large, well-known oil companies and independent refiners with whom we have longstanding relationships.

The following table highlights the storage capacity, number of loading lanes, number of tanks, supply source, mode of distribution and average daily throughput of our refined products terminals:

North Little Rock terminal.  Our North Little Rock terminal consists of 11 storage tanks with an aggregate capacity of approximately 550,000 barrels and has eight loading lanes with automated truck loading equipment to minimize wait time for our customers. Our truck loading racks are capable of providing automated computer blending to customer specifications. The North Little Rock terminal handles products such as multi-octane conventional gasoline, ultra-low sulphur diesel with dye-at-rack capability, bio-diesel with ratio blending capability and ethanol. This terminal is supplied by two receipt lines from the TEPPCO Pipeline, one for ultra-low sulphur diesel and the other for all other refined products, and has full offloading capability for 10 rail cars of ethanol at a time via a rail spur served by the Union Pacific system via the Genesee and Wyoming Railroad. Our North Little Rock terminal serves the Little Rock metropolitan area, which grew 15% from 2000 to 2010 according to Census Bureau data, and is expected to grow another 11% by 2025.

Caddo Mills terminal.  Our Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment to minimize wait time for our customers. This terminal is served by the Explorer Pipeline and has truck loading racks capable of providing automated computer blending to customer specifications. Our Caddo Mills terminal handles products such as conventional blend stock for oxygenate blending (CBOB) gasoline, reformulated blend stock for oxygenate blending (RBOB), premium blend stock for oxygenate blending (PBOB), ethanol, ultra-low sulphur diesel with dye-at-rack capability and bio-diesel with ratio blending capability. We own approximately 6 additional acres of land at our Caddo Mills terminal that is available for future expansion. Management estimates that this acreage is capable of housing an additional 200,000 barrels of storage capacity. The Caddo Mills terminal serves Collin County, located in the northeast portion of the Dallas-Fort Worth metroplex, which, according to Census Bureau data, grew 23% from 2000 to 2010, making it one of the fastest growing large markets in the United States.

NGL Distribution and Sales

Cylinder Exchange

We currently operate the third-largest propane cylinder exchange business in the United States, which consists of the distribution of propane-filled cylinder tanks typically used in barbeque grilling and which covers all 48 states in the continental United States through a network of over 18,800 distribution locations. We market our business under the brand name Pinnacle Propane Express or under the brand names of our customers. Our customers include grocery stores, pharmacies, convenience stores and hardware retailers which sell or exchange our propane-filled cylinders to consumers for end-use. For the year ended December 31, 2014, we sold or exchanged approximately 4.8 million propane cylinders containing approximately 16.8 million aggregate gallons of propane, representing a 6% increase in cylinder sales and exchanges compared to the same period during the previous year. We believe our cylinder exchange business is strategically positioned for continued growth resulting from the overall increase in demand and extended applications for portable propane cylinders and our recently completed expansion in the western United States.

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We generate revenues in our cylinder exchange business through the sale or exchange of propane-filled cylinders at an agreed upon contract price. For the years ended December 31, 2014 and December 31, 2013, we distributed 54% and 51%, respectively, of our propane volumes in our cylinder exchange business under long-term agreements and the remaining 46% and 49%, respectively, under one-month contracts or on a spot/demand basis. As of December 31, 2014, our contracts had a weighted average remaining term of approximately 1.9 years. Our long-term cylinder exchange agreements typically permit us to adjust our prices at the time of contract renewal while our month-to-month cylinder exchange agreements allow us to pass our costs on to our customers and thereby minimize our commodity price exposure. In order to manage our cost of propane we enter into hedging arrangements on all fixed-price contracts. We use financial swaps to hedge a majority of the forecasted volumes in our cylinder exchange business, where approximately half of our sales volumes are under contracts with two- and three-year terms.

Cylinder production cycle.  We own nine production facilities strategically located in Alabama, Illinois, Michigan, Missouri, Nevada, Oregon, Pennsylvania, South Carolina and Texas. Our production facilities receive inbound pallets of empty 20-pound propane cylinders, which are put through a processing cycle that includes cleaning, inspection, testing, painting, refilling and loading onto relay trucks for delivery to our 56 distribution depot locations. Drivers at our depots receive the full cylinders from our production facilities for delivery to our customer service locations and pick up empty cylinders, which are shipped to our production facilities for processing.

NGL Sales

Our NGL sales business involves the retail, commercial and wholesale sale of NGLs and other refined products (including sales of gasoline and diesel to our oilfield service and agricultural customers) in seven states in the Southwest and Midwest to approximately 96,900 customers through our distribution network of 34 customer service locations. We generate revenues by charging a price per gallon consisting of our product supply, transportation, handling, and storage costs plus a margin. Our contracts permit us to pass through our supply costs on a regular basis, thereby limiting our commodity price exposure. Since July 2010, we have acquired 17 propane franchises to expand our market presence within our operating region in Texas, Oklahoma, New Mexico, Arizona, Arkansas and Missouri.

Customers.  We sell propane, butane and refined fuels, including diesel, gasoline, lubricants and solvents, primarily to three customer markets: retail, commercial and wholesale, which include a mix of residential, commercial, agricultural, oilfield service and industrial customers. The customer service centers in our NGL sales business are located in suburban and rural areas where natural gas is not readily available. These customer service centers generally consist of an office, warehouse and service facilities, with one or more 2,500 to 45,000 gallon storage tanks on the premises. These tanks are used to supply our bobtail trucks, which in turn make deliveries to our retail customers. Customers can also bring their own NGL storage containers to our customer service centers to be filled.

Retail.  We primarily serve residential customers through the sale of propane for home heating and power generation. We deliver propane through our 125 active bobtail trucks, which have capacities ranging from 2,000 gallons to 5,000 gallons of propane into stationary storage tanks on our customers’ premises. Tank ownership and control at customer locations are important components of our operations and customer retention, and account for approximately half of our retail volumes. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 12,000 gallons, with a typical tank having a capacity of 250 to 500 gallons. We also offer a propane supply commitment program to customers who own their own tanks that we believe increases customer loyalty. Under the program, customers receive progressively larger discounts off our posted prices each year that they remain as our customer. We also offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period.

In Arizona, our subsidiary, Alliant Arizona Propane, L.L.C., sells propane to residential and commercial customers through regulated central distribution systems in Payson and Page, Arizona that utilize pipelines to distribute propane through meters at the customer’s location. Alliant Arizona Propane, L.L.C. is a regulated utility that receives a fixed cost-plus fee for propane sold. Another subsidiary, Alliant Gas, serves 25 communities in Texas and two communities in Arizona through regulated central distribution systems pursuant to long-term contracts. Net customer turnover at Alliant Gas is nearly zero.

Commercial.  Our commercial customers include a mix of industrial customers, hotels, restaurants, churches, warehouses and retail stores. These customers generally use propane for the same purposes as our residential customers as well as industrial, oilfield service and agricultural customers, who use propane and refined fuels, such as gasoline and diesel, for heating requirements and as fuel to power over-the-road vehicles, forklifts and stationary engines.

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Wholesale.  Our wholesale customers are principally governmental agencies and other propane distributors. Our LPG transports, which are large trucks that have capacities ranging from 9,000 to 11,500 gallons, load propane at third-party supply points for delivery directly to tanks located on the property of our wholesale customers.

Product supply.  We utilize approximately 20 domestic sources of propane supply, including spot market purchases, with four suppliers providing a substantial portion of our propane. Our propane supply contracts are typically from agreements with one-year terms and standard commercial provisions. During the years ended December 31, 2014 and December 31, 2013, we purchased the majority of our propane needs from these four suppliers.

Our supply group manages and sources propane to ensure secure and reliable supply throughout the year. Our LPG transports pick up propane at our supply points, typically refineries, natural gas processing and fractionation plants or LPG storage terminals, for delivery to our customer service centers and our wholesale customers. Supplies of propane from our sources historically have been readily available. During the years ended December 31, 2014 and December 31, 2013, approximately 87% and 76%, respectively, of our propane supply was purchased under supply agreements, which typically have a term of one year, and the remainder on the spot market.

Our supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas or (ii) posted prices at the time of delivery. We use a variety of delivery methods, including our LPG transports and common carrier transports, to transport propane from suppliers to our customer service locations as well as various third-party storage facilities and terminals located in strategic areas across our area of operations. In order to manage our cost of propane, we enter into hedging arrangements on all fixed-price contracts.

NGL Transportation

In October 2013 we expanded our NGL distribution and sales segment by acquiring a fleet of approximately 43 hard shell tank trucks that gather and transport NGLs and condensate for producers, gas processing plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin. For the years ended December 31, 2014 and December 31, 2013, our NGL transportation trucks transported approximately 311,733 gallons per day and 203,005 gallons per day, respectively, of NGLs.

Competition

Crude oil pipelines and storage.  We are subject to competition from other crude oil pipelines, crude oil storage tank operators and crude oil marketing companies that may be able to transport or store crude oil at more favorable prices or transport crude oil greater distance or to more favorable markets. We compete with national, regional and local crude oil pipeline transportation and storage companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in our crude oil storage segment include Plains All American Pipeline, L.P., Occidental Petroleum Corporation, SemGroup Corporation, Rose Rock Midstream, L.P., Blueknight Energy Partners, L.P., Medallion Midstream LLC and Enterprise Products Partners L.P.

Crude oil supply and logistics.  We are subject to competition from other providers of crude oil supply and logistics services that may be able to supply our customers with the same or comparable services on a more competitive basis. We compete with national, regional and local storage, gathering, transportation and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in this segment include Plains All American Pipeline, L.P., Rose Rock Midstream, L.P., Blueknight Energy Partners, L.P., SemGroup Corporation, Sunoco Logistics, Enterprise Products Partners L.P., Genesis Energy, L.P. and NGL Energy Partners L.P.

Refined products terminals and storage.  Our refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas compete with other independent terminals on price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading activities. In the North Little Rock, Arkansas market, these competitors include Magellan Midstream Partners LP and HWRT Oil Company, LLC. In Dallas, Texas, the market served by our Caddo Mills, Texas terminal, these competitors include Valero Energy Corporation, Delek Logistics Partners, LP, Magellan Midstream Partners LP and Flint Hills Resources LP.

NGL distribution and sales.  In addition to competing with suppliers of other energy sources such as natural gas, our NGL distribution and sales segment competes with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers,

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thousands of smaller local independent marketers and farm cooperatives. The large, full-service multi-state marketers we compete with include Ferrellgas, L.P. and AmeriGas Partners, L.P. Each of our customer service centers operates in its own competitive environment because retail marketers tend to be located in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

Customers

We rely on a limited number of customers for a substantial portion of our revenues. Glencore, Ltd., Chesapeake Energy Marketing, Inc. and Phillips 66 each accounted for 10% or more of our total revenue for the year ended December 31, 2014, at approximately 37%, 10% and 10%, respectively.

Seasonality

Weather conditions have a significant impact on the demand for our products, particularly propane and refined fuels for heating purposes. Many of our customers rely on propane primarily as a heating source. Accordingly, the volumes sold are directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures, as was the case in the heating season over the last three years throughout our operating territories, will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption. Meanwhile, our cylinder exchange operations experience higher volumes in the spring and summer, which includes the majority of the grilling season. Sustained periods of poor weather, particularly in the grilling season, can negatively affect our cylinder exchange revenues. In addition, poor weather may reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange.

The volume of propane used by customers of our NGL sales business is higher during the first and fourth calendar quarters and lower during the second and third calendar quarters. Conversely, the volume of propane that we sell through our cylinder exchange business is higher during the second and third calendar quarters and lower in the first and fourth calendar quarters. We believe that our combination of our winter-weighted NGL sales business with our higher-margin, summer-weighted cylinder exchange business reduces overall seasonal fluctuations in volumes and financial results, as our cylinder exchange business is more active in summer months and our NGL sales business is more active in winter months. The impact of seasonality is also mitigated by non-heating related demand throughout the year for propane for oilfield services, fuel for automobiles and for industrial applications, such as forklifts, mowers and generators. For the year ended December 31, 2014, we sold approximately 73 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 43% in the second and third quarters of 2014 and 57% in the first and fourth quarters of 2014.

The volume of product that is handled, transported, throughput or stored in our refined products terminals is directly affected by the level of supply and demand in the wholesale markets served by our terminals. Overall supply of refined products in the wholesale markets is influenced by the absolute prices of the products, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the market’s perception of future product prices. Although demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, most of the revenues generated at our refined products terminals do not experience any effects from such seasonality. However, the butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

Insurance

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain our own property, business interruption and pollution liability insurance policies at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets. As we continue to grow, we will continue to evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

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Regulation of the Industry and Our Operations

Crude Oil

We own and operate a fleet of trucks to transport crude oil. We are licensed to perform both intrastate and interstate motor carrier services and are subject to certain safety regulations issued by the DOT. DOT regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment and many other aspects of our trucking operations. Our trucking operations are also subject to regulations and oversight by the Occupational Safety and Health Administration. Additionally, our Silver Dollar Pipeline System is subject to the regulatory oversight of the Texas Railroad Commission and the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”).

Refined Products and NGLs

All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. We maintain various permits necessary to ensure that our operations comply with applicable regulations. We conduct training programs to help ensure that our operations are in compliance with applicable governmental regulations. With respect to general operations, certain National Fire Protection Association (“NFPA”) Pamphlets, including Nos. 54 and 58 and/or one or more of various international codes (including international fire, building and fuel gas codes) establish rules and procedures governing the safe handling of propane, or comparable regulations, which have been adopted by all states in which we operate. In addition, Alliant Arizona Propane, LLC is subject to regulation by the Arizona Corporation Commission and Alliant Gas, LLC is subject to regulation by the Texas Railroad Commission. We believe that the policies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

With respect to the transportation of NGLs, including propane, by truck, we are subject to regulation by PHMSA under the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, among other statutes. Our propane gas pipeline systems are also subject to regulation by the PHMSA under the Natural Gas Pipeline Safety Act of 1968, which applies to, among other things, a propane gas system that supplies ten or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators of all gas systems to train employees and third-party contractors, establish written procedures to minimize the hazards resulting from gas pipeline emergencies and conduct and keep records of inspections and testing.

PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators, including us, to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. Effective October 25, 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. PHMSA also has published an advisory bulletin providing guidance on verification of records related to pipeline maximum operating pressure. We have performed hydrotests of our facilities to confirm the maximum operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum operating pressure would materially affect our operations or revenue.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most states are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines.

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Management believes that the policies and procedures currently in effect at all of our propane gas systems are consistent with industry standards and are in compliance with applicable law. Due to our ownership and control of these gas utility companies, we are required to notify FERC of our status as a holding company. We filed such a notification of holding company status and we qualified for an exemption from FERC accounting regulations and access to our books and records because we are a holding company solely by reason of our interests in local gas distribution systems.

Environmental Matters

General

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of certain terminals, storage and transportation facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

·                  requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

·                  limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

·                  delaying system modification or upgrades during permit reviews;

·                  requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

·                  enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or permit requirements imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict

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requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste. However, it is possible that wastes currently designated as non-hazardous, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act

Th Oil Pollution Act (“OPA”) requires the preparation of a Spill Prevention Control and Countermeasure Plan (“SPCC”) for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training.

Air Emissions

Our operations are subject to the Clean Air Act (“CAA”) and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

On August 20, 2010, the EPA published regulations to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines, which was later amended in response to several petitions for reconsideration. The rule requires us to make certain expenditures and undertake certain activities, including the purchase and installation of emissions control equipment (e.g. oxidation catalysts, non-selective catalytic reduction equipment) on our engines following prescribed maintenance practices. In addition, on June 28, 2011, the EPA issued a final rule that establishes new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. This rule requires us to purchase, install, monitor and maintain emissions control equipment.

Water Discharges

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters and impose requirements affecting our ability to conduct construction activities in waters and wetlands.. In addition, these laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose

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administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Endangered Species

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. In addition, as a result of a settlement approved by the United States District Court for the District of Columbia on September 9, 2011, the United States Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011 settlement, the United States Fish and Wildlife Service is required to review and address the needs of more than 250 species on the candidate list over a 6-year period. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and propane exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

Hydraulic Fracturing

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

Climate Change

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Accordingly, the EPA adopted emissions limits for motor vehicles, which then triggered the development and adoption of construction and operating permit requirements under the Prevention of Significant Deterioration and Title V programs for certain stationary sources. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis. In December 2014, the EPA proposed additional amendments to its greenhouse gas reporting rule, which could add reporting requirements for additional facilities.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or regulatory programs

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could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Anti-terrorism Measures

Certain of our bulk storage facilities are also subject to regulation by the Department of Homeland Security (“DHS”). The Department of Homeland Security Appropriation Act of 2007 requires the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

Trademarks and Tradenames

We utilize a variety of trademarks and tradenames which we own or have the right to use, including “Pinnacle Propane,” “Pinnacle Propane Express” and “Alliant Arizona Propane.” We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. As of March 2, 2015, our general partner and its affiliates have approximately 909 employees performing services for our operations. None of these employees are covered by collective bargaining agreements and we believe that our general partner and its affiliates have a satisfactory relationship with their employees.

Available Information

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the Securities and Exchange Commission (“SEC”). You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the public reference room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through our website located at www.jpenergypartners.com. References to our website or any other website in this Annual Report on Form 10-K are not incorporated by reference into this report and do not constitute part of this report.

ITEM 1A. RISK FACTORS

The occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report on Form 10-K or in any other of our filings with the SEC could have a material adverse effect on our business, financial position, results of operations and cash flows. In evaluating an investment in any of our securities, you should consider carefully, among other things, the factors and the specific risks set forth below. This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. See “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the factors that could cause our actual results to differ materially from those projected.

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Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.3250 per unit per quarter, or $1.30 per unit on an annualized basis, we require available cash of approximately $12.0 million per quarter, or $48.0 million per year. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

·                  the price of, and the demand for, crude oil, refined products and NGLs in the markets we serve;

·                  the volumes of crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and our NGL sales volumes;

·                  the fees we receive for the crude oil, refined products and NGL volumes we handle;

·                  pressures from our competitors, some of which may have significantly greater resources than us;

·                  the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass along cost increases to our customers;

·                  competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;

·                  the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to replace such contracts and/or customers;

·                  leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;

·                  the level of our operating, maintenance and general and administrative expenses; and

·                  regulatory action affecting our existing contracts, our operating costs or our operating flexibility.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

·                  the level of capital expenditures we make;

·                  our cost of acquisitions, if any;

·                  our debt service requirements and other liabilities;

·                  expenses that our general partner incurs on our behalf and are reimbursed by us, which expenses are not subject to any caps or other limits pursuant to our partnership agreement;

·                  fluctuations in our working capital needs;

·                  our ability to borrow funds and access the capital markets;

·                  restrictions contained in our revolving credit facility and other debt agreements;

·                  the amount of cash reserves established by our general partner; and

·                  other business risks affecting our cash levels.

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A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues.

A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues, which could have a material adverse effect on our financial condition, results of operations and cash flows. Factors that could lead to a decrease in market demand for crude oil, refined products or NGLs include:

·                  lower demand by consumers for refined products or crude oil as a result of adverse economic conditions, an increase in the market price of crude oil, an increase in the market price of gasoline or other refined products, use by consumers of alternative fuels or an increase in the fuel economy of vehicles;

·                  lower drilling activity in the areas served by our crude oil gathering and transportation business as a result of a decrease in the market price of crude oil or for other reasons; and

·                  fluctuations in the demand for crude oil, such as those caused by refinery downtime or shutdowns.

Certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, we may experience declines in our margin and profitability if our volumes decrease.

We have several short-term contracts and other contracts that can be canceled on 60 days’ notice and will have to be renegotiated or replaced periodically. Our failure to replace contracts that are canceled or expire on acceptable terms, or at all, could cause our revenues to decline and reduce our ability to make distributions to our unitholders.

Many of our contracts in our NGL sales and distribution segment have terms as short as one month, and substantially all of our contracts with customers in our refined products terminals and storage segment have evergreen provisions after an initial term of six months to two years and are cancellable on as little as 60 days’ notice. In addition, many of our contracts in our crude oil supply and logistics segment either have terms as short as one month or have evergreen provisions and are cancellable on as little as 60 days’ notice. As these NGL or crude oil contracts expire or if a refined products contract is canceled, we may not be able to extend, renegotiate or replace these contracts and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. In addition, while the majority of the revenue in our crude oil pipelines and storage segment is generated pursuant to long-term contracts, our customers may negotiate for more favorable terms upon any renewal.

Our ability to extend or replace contracts could be impacted by a number of factors beyond our control, including competition, the level of supply and demand for crude oil and refined products in our areas of operations, general economic conditions and regulatory developments. To the extent we are unable to renew our contracts on terms that are favorable to us, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.

We face competition in all of our business segments. Competitors that are able to supply our customers with similar services or products at a lower price could reduce our revenues.

We are subject to competition from other providers of crude oil transportation, storage, supply and logistics services, refined products terminals and storage services and NGL distribution and sales services, including national, regional and local companies engaged in these activities. Some of these competitors are substantially larger than us and may have greater financial resources. Our ability to compete could be affected by many factors, including:

·                  price competition;

·                  the perception that another company can provide better service; and

·                  the availability of alternative supply points, or supply points located closer to the operations of our customers.

In addition, our general partner and its affiliates, including JP Development, Lonestar and ArcLight, may engage in competition with us. If we are unable to compete with services offered by our competitors, including possibly our general partner or its affiliates, it could have a material adverse effect on our financial condition, results of operations and cash flows.

We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Prior to the completion of our initial public offering, we were a private entity with limited accounting personnel and

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other supervisory resources to adequately execute our accounting processes and address our internal control over financial reporting. In connection with the audits of our financial statements for the years ended December 31, 2011, 2012 and 2013, our independent registered public accounting firm identified material weaknesses in internal control over financial reporting relating to (1) accounting resources and policies (including maintaining an effective control environment), (2) accounting for business combinations and (3) information technology. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We did not have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements. As a result, we did not design and maintain:

·                  formal accounting policies and formal review controls;

·                  effective controls over accounting for business combinations, including controls related to the valuation of assets acquired and liabilities assumed, and the integration of the businesses by applying consistent accounting policies and processes to determine compliance with industry standards and regulations; and

·                  adequate policies and procedures with respect to the primary components of information technology general controls, including the approval and review of access controls, system implementation and migration controls, and change management controls.

These material weaknesses resulted in audit adjustments in the years ended December 31, 2011, 2012 and 2013 and the three months ended March 31, 2012 and 2013, and six months ended June 30, 2013, and a restatement of our financial statements for the years ended December 31, 2011 and 2012, and the three months ended March 31, 2012 and 2013. Management has also determined that the excess product gains at a refined products terminal described in Note 15 to the consolidated financial statements for the year ended December 31, 2014 was an additional effect of the material weakness related to business combinations and information technology described above.

We are currently working 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 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.

If we do not properly maintain and improve our measurement and quality control processes and procedures across all of our business segments, we may have measurement and quality errors or contamination, which may result in lost revenues or the incurrence of additional costs.

We are implementing measurement and quality control processes and procedures across all of our business segments. To the extent we do not properly maintain and improve such procedures, we may have measurement and quality errors or contamination that could result in lost revenues or the incurrence of additional costs. For example, in the third quarter of 2014 we became aware that certain of our measurement and quality control processes at our North Little Rock terminal were not in compliance with certain industry standards and had resulted in excess product gains for the North Little Rock terminal. We have notified our customers and have returned a certain amount of refined products to the majority of such customers for the period from November 2012 (the month we acquired the North Little Rock terminal) through July 2014. If we are unable to reach a resolution on this matter with the remaining customer, it may assert claims against us for damages. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims, if any are ultimately asserted. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur costs that could have a negative effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We are not currently required to make an assessment of our internal control over financial reporting.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002 (“Sarbanes Oxley”) and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Sections 302 and 404 of Sarbanes Oxley, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Although we are required to disclose changes made to our internal control over financial reporting and procedures on a

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quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of Sarbanes Oxley and our independent registered public accounting firm will not be required to issue an attestation report on the effectiveness of our internal control over financial reporting until the fiscal year ending December 31, 2015. In order to have effective control over financial reporting, we will need to implement additional internal controls, reporting systems and procedures.

Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal control over financial reporting, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal control over financial reporting will subject us to regulatory scrutiny and could result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Because of the natural decline in production from our customers’ existing wells in our areas of operation, we depend, in part, on producers replacing declining production and also on our ability to secure new sources of crude oil. Any decrease in the volumes of crude oil that we transport could adversely affect our business and operating results.

The crude oil volumes that support our crude oil pipelines and storage segment and crude oil supply and logistics segment depend on the level of production from crude oil wells on which we rely for throughput or sales and transportation volumes, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput or sales and transportation volumes in these segments, we must obtain new sources of crude oil. In our crude oil pipelines and storage segment, the primary factors affecting our ability to obtain non-dedicated sources of crude oil include (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells on which we rely for throughput or sales and transportation volumes or the rate at which production from such wells declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

·                  the availability and cost of capital;

·                  prevailing and projected oil, natural gas and NGL prices;

·                  demand for oil, natural gas and NGLs;

·                  levels of reserves;

·                  geological considerations;

·                  environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

·                  the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of oil reserves. Drilling and production activity generally decreases as oil prices decrease. Declines in oil prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in exploration and production activity. Any sustained decline of exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

Because of these and other factors, even if oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain throughput in our crude oil pipelines and storage segment and our sales and transportation volumes in our crude oil supply and logistics segment, our revenue and cash flow could be reduced and our ability to make cash distributions to our unitholders could be adversely affected.

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We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis; therefore, in the future, volumes of oil on our Silver Dollar Pipeline System could be less than we anticipate.

We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to our Silver Dollar Pipeline System or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our Silver Dollar Pipeline System are less than we anticipate and if our customers are unable to secure additional sources of crude oil production it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our success in our crude oil pipelines business depends, in part, on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.

Our Silver Dollar Pipeline System is located in the Midland Basin and we intend to focus future capital expenditures on developing our business in this area. Due to our focus on the Spraberry, Wolfberry and Wolfcamp plays in the Midland Basin, an adverse development in oil production from this area would have a greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Midland Basin or a continued decline in oil prices could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We may not be able to increase throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our crude oil pipelines and storage segment.

Our ability to increase our throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which our Silver Dollar Pipeline System has available takeaway capacity. To the extent that we lack available capacity on our Silver Dollar Pipeline System for additional volumes, we may not be able to compete effectively with third-party systems for additional oil production in our areas of operation. In addition, our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to contracts that are effectively fee-based. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

Our crude oil supply and logistics operations involve market and regulatory risks.

As part of our crude oil supply and logistics activities, we purchase crude oil at prices determined by prevailing market conditions. Following our purchase of crude oil, we generally resell crude oil at a higher price under a sales contract that is generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our crude oil logistics operations may be affected by the following factors:

·                  our ability to negotiate crude oil purchase and sales agreements in changing markets on a timely basis;

·                  reluctance of customers to enter into long-term purchase contracts;

·                  consumers’ willingness to use other fuels instead of the end products in the crude oil supply chain;

·                  the timing of imbalance or volume discrepancy corrections and their impact on our financial results;

·                  the ability of our customers to make timely payment; and

·                  any inability we may have to match purchase and sale of crude oil on comparable terms.

We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.

We rely on a limited number of customers for a substantial portion of our revenues. Glencore, Ltd., Chesapeake Energy Marketing, Inc. and Phillips 66 each accounted for 10% or more of our total revenue for the year ended December 31, 2014, at approximately 37%, 10% and 10%, respectively. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms or at all. In addition, these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our

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customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. Furthermore, our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Midstream capacity constraints and interruptions could impact our operations.

We rely on various midstream facilities and systems in connection with our crude oil supply and logistics operations. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of the supply in our crude oil supply and logistics business may be interrupted or shut-in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed in connection with our crude oil supply and logistics operations. Such interruptions or constraints could negatively impact our profitability.

The risk management policy governing our crude oil supply activities cannot eliminate all risks associated with our crude oil supply and logistics business, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.

We have in place a risk management policy that seeks to establish limits for the exposure in our crude oil supply and logistics business by requiring that we restrict net open positions through the concurrent purchase and sale of like quantities of crude oil to create transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Our risk management policy, however, cannot eliminate all risks. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.

Moreover, we are exposed to price movements on products that are not hedged, such as our crude oil linefill, which must be maintained to operate our crude oil pipeline system. We are also exposed to certain price risks related to basis differentials. Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality at a location or at a time that differs from the specific delivery terms with respect to grade, quality, time or location of the applicable offsetting agreement. If this occurs, we may not be able to use the physical markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.

We are also subject to the risk that employees of our general partner involved in our crude oil supply operations may not comply at all times with our risk management policy. We cannot ensure that all violations of our risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.

A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for the services we provide in our crude oil storage business.

In recent years, a shortfall in takeaway pipeline capacity has at times led to an oversupply of crude oil at Cushing. This was cited as a principal reason for the decline in the West Texas Intermediate Index (“WTI Index”) price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index over the same period. While the WTI Index price has recovered compared to the Brent Crude Index, a renewed decline in the WTI Index price relative to other index prices may reduce demand for our transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

The results of our crude oil storage business could be adversely affected during periods in which the overall forward market for crude oil is backwardated.

The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at

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higher prices for future delivery. Conversely, a backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered for future delivery are expected to be lower. Accordingly, a backwardated market can negatively impact the demand for crude oil storage. If the forward market for crude oil is backwardated at times when we are renewing our crude oil storage contract or entering into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.

All of our operations have indirect exposure to changes in commodity prices and some of our operations have direct exposure to commodity price changes.

Our operations have limited direct exposure to changes in commodity prices. However, the volumes of crude oil that we transport, store or supply, refined products that we handle and NGLs that we distribute and sell are indirectly affected by commodity prices because many of our customers have direct exposure to commodity prices. If our customers are negatively impacted by changes in commodity prices, they may, among other things, reduce the services they purchase from us. For example, lower crude oil prices could suppress drilling activity, which would reduce demand for our crude oil pipeline, storage or supply and logistics services, while higher refined products prices could decrease consumer demand for refined products, which could reduce demand for services we provide at our refined products terminals.

In addition, in our refined products terminals and storage segment, we also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. Our blending activities are subject to direct commodity price exposure. Any significant reduction in the amount of services we provide to our customers because of direct or indirect commodity price exposure and any significant reduction in the refined products that we sell could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We do not operate our crude oil storage facility.

TEPPCO Partners L.P., a wholly owned subsidiary of Enterprise Products Partners L.P., serves as the operator of our crude oil storage facility. Under the operating agreement governing TEPPCO’s operation of our facility, we are liable for any losses or claims arising from damage to our property or personal injury claims of our personnel that may result from the actions of the operator, even if such losses or claims result from the operator’s gross negligence or willful misconduct. If disputes arise over operation of our crude oil storage facility, or if our operator fails to provide the services contracted under the agreement, our business, results of operation, financial condition and ability to make cash distributions to our unitholders could be adversely affected.

Changes in trucking regulations may increase our costs or make it more difficult for us to attract or retain qualified drivers, which could negatively affect our results of operations.

In connection with the services we provide, we operate as a motor carrier and, therefore, are subject to regulation by the Department of Transportation (the “DOT”), and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry that we are subject to, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. These possible changes include increasingly stringent environmental regulations, changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

In addition, the already substantial competition for qualified drivers in the trucking industry may increase because of regulatory requirements. For instance, Comprehensive Safety Analysis 2010 (“CSA”) has been implemented by the Federal Motor Carrier Safety Administration, an agency of the DOT, to monitor and improve commercial motor vehicle safety by measuring the safety record of both the motor carrier and the driver. The requirements of CSA could shrink the pool of qualified drivers and increase the costs we incur in order to attract, train and retain qualified drivers. In addition, a shortage of qualified drivers could increase driver turnover rates, which might limit growth in our crude oil supply and logistics or other segments.

Our refined products terminals are dependent upon their interconnections with terminals and pipelines owned and operated by others.

Our refined products terminals are dependent upon their interconnections with other terminals and pipelines owned and operated by third parties to reach end markets and as a significant source of supply. Our North Little Rock terminal is supplied by the TEPPCO Pipeline while our Caddo Mills terminal is supplied by the Explorer Pipeline. Reduced or interrupted throughput on these pipelines or outages at terminals with which our refined products terminals share

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interconnects because of weather or other natural events, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver refined products to our customers from our terminals or receive products for storage at our terminals, which could adversely affect our cash flows and revenues. In addition, in the event that one of the pipelines depended upon by either of our refined products terminals modifies its tariff to discontinue service for one or more of the products throughput at our terminals, we will have to discontinue selling or secure an alternate supply of such product. This could have a material adverse impact on the throughput volumes and revenues of our refined products terminals and storage segment.

The assets in our refined products terminals and storage segment have been in service for several decades.

Our refined products terminals and storage assets are generally long-lived assets. Our North Little Rock terminal has been in service for approximately 35 years, and our Caddo Mills terminal has been in service for approximately 30 years. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Warm weather in the winter heating season or inclement weather in the summer grilling season could lower demand for propane.

Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Many of our customers rely on propane primarily as a heating source during the winter. For the year ended December 31, 2014, we sold approximately 65% of our retail, commercial and wholesale propane volumes during the first and fourth quarters of the year.

Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, in 2014 the average temperature in the seven states in which we operate was 4% warmer than normal, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (“NOAA”).

Conversely, our cylinder exchange business experiences higher volumes in the spring and summer, which includes the majority of the grilling season. For the year ended December 31, 2014, we sold approximately 57% of the propane volumes in our cylinder exchange business during the second and third quarters of the year. Sustained periods of poor weather, particularly in the grilling season, can reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange and our outdoor products.

Sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements and these contracted pricing arrangements will adversely affect our profit margins if they are not immediately hedged with an offsetting propane purchase commitment.

Results of operations related to the retail distribution of propane is primarily based on the cents-per-gallon difference between the sales price we charge our customers and our costs to purchase and deliver propane to our propane distribution locations. We enter into propane sales commitments with a portion of our customers that provide for a contracted price agreement for a specified period of time. The propane cost per gallon is subject to various market conditions and may fluctuate based on changes in demand, supply and other energy commodity prices, such as crude oil and natural gas prices. We employ risk management techniques that attempt to mitigate risks related to the purchasing, storing, transporting and selling of propane. However, sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements. In addition, even upon the expiration of short-term contracts, we may face competitive or relationship pressure to minimize any price increases. Therefore, these commitments expose us to product price risk and reduced profit margins if those transactions are not immediately hedged with an offsetting propane purchase commitment.

High prices for propane can lead to customer conservation and attrition, resulting in reduced demand for our products.

Propane prices are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane commodity market conditions. During periods of high propane costs our selling prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.

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We are dependent on certain principal propane suppliers, which increases the risks from an interruption in supply and transportation.

During the year ended December 31, 2014, we purchased 66% of our propane needs from four suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and our earnings could be affected. Additionally, in certain areas, based on favorable pricing or the strategic location of certain supply points, a single supplier may provide more than 75% of our propane requirements for that area. Although we have relationships with other suppliers in these areas and have the ability to acquire product elsewhere, in the event of a supply disruption with our primary suppliers in certain regions, we could be forced to purchase propane at a less favorable price and with a higher transportation cost. Accordingly, disruptions in supply in certain areas could also have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Energy efficiency, advances in technology and competition from other energy sources may affect demand for propane and increases in propane prices may cause our residential customers to increase their conservation efforts.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has generally reduced the demand for propane. Propane also competes with other sources of energy such as electricity, natural gas and fuel oil, some of which can be less costly for equivalent energy value. In particular, the gradual expansion of the nation’s natural gas distribution systems has increased the availability of affordable natural gas in rural areas, which historically found propane to be the more cost-effective choice. We cannot predict the effect that future conservation measures, technological advances in heating, conservation, energy generation or other devices or the development of alternative energy sources might have on our operations. As the price of propane increases, some of our customers tend to increase their conservation efforts and thereby decrease their consumption of propane.

If the independently owned third-party haulers that we rely upon for the delivery of propane cylinders from our production facilities to certain of our distribution depots do not perform as expected, or if we or these third-party haulers are not able to manage growth effectively, our relationships with our customers may be adversely impacted and our delivery of propane by cylinder exchange may decline.

We rely in part on independently owned third-party haulers to deliver cylinders from our production facilities to certain of our distribution depots. Accordingly, our success depends on our ability to maintain and manage relationships with these third-party haulers. We exercise only limited influence over the resources that the third-party haulers devote to the delivery of cylinders. We could experience a loss of consumer or retailer goodwill if our third-party haulers do not adhere to our quality control and service guidelines or fail to ensure the timely delivery of an adequate supply of propane cylinders to certain of our production depots. In addition, the number of retail locations accepting delivery of our propane by cylinder exchange and, subsequently, the retailer’s corresponding sales have historically grown significantly along with the creation of our third-party hauler network. Accordingly, our haulers must be able to adequately service an increasing number of propane cylinder deliveries to our distribution depots so that we can service our retail accounts. If we or our third-party haulers fail to manage the growth of our cylinder exchange operations effectively, our financial results from our delivery of propane by cylinder exchange may be adversely affected.

A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.

Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil supply and logistics and NGL distribution and sales segments. Because we do not attempt to hedge motor fuel price risk, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and weather concerns. Additionally, we may be affected by increases in the cost of materials used to produce portable propane cylinders. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

Our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts could have a material adverse effect on our financial condition, results of operations and cash flows.

We enter into hedging arrangements on a rolling twelve-month basis to manage the cost of propane in our cylinder exchange business. We also may from time to time enter into derivative instruments to hedge our exposure to variable interest rates. Volatility in the oil and gas commodities sector for an extended period of time or intense volatility in the near-term could impair our or our counterparties’ ability to meet margin calls, which could cause us or our counterparties to default on commodity and financial derivative contracts. This could have a material adverse effect on our liquidity or our ability to procure product supply at prices reasonable to us or at all.

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We are exposed to the credit risks, and certain other risks, of our key customers and other counterparties.

In connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for (i) certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition, (ii) certain matters arising from the pre-closing ownership and operation of assets and (iii) ongoing remediation related to the assets. Our business, results of operations, financial condition and our ability to make cash distributions to our unitholders could be adversely affected in the future if these third parties fail to satisfy an indemnification obligation owed to us.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from JP Development, ArcLight Fund V or third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow is dependent, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based in large part on our expectation of ongoing divestitures of midstream energy assets by industry participants, including our affiliates. Subject to the right of first offer granted to us, JP Development and ArcLight Fund V are under no obligation to offer to sell us assets and a material decrease in such divestitures by industry participants would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

If we are unable to make accretive acquisitions, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from our operations on a per unit basis.

Any acquisition involves potential risks, including, among other things:

·                  mistaken assumptions about volumes, revenue and costs, including operational synergies;

·                  an inability to secure adequate customer commitments to use the acquired assets or businesses;

·                  an inability to successfully integrate the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;

·                  the assumption of unknown liabilities;

·                  limitations on rights to indemnity from the seller;

·                  unforeseen difficulties operating in new geographic areas and business lines; and

·                  customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our right of first offer to acquire certain ArcLight assets and all of JP Development’s existing and future assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.

Our Right of First Offer Agreement with JP Development and ArcLight Fund V provides us with a right of first offer on (i) JP Development’s existing and future assets for a period of five years from the closing of our initial public offering and (ii) ArcLight Fund V’s indirect 50% interest in Republic for a period of eighteen months from the closing of our initial public offering. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, JP Development’s and ArcLight Fund V’s willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant

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to our right of first offer, and JP Development and ArcLight Fund V are under no obligation to accept any offer that we may choose to make in response to any notice by JP Development or ArcLight Fund V of their intent to transfer assets. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any of JP Development’s or ArcLight Fund V’s assets are offered for sale, and our decision will not be subject to unitholder approval.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing assets and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.

We continuously consider potential acquisitions and opportunities for organic growth projects. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, changes in key benchmark interest rates, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or the capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our growth strategy, enhance our existing business, complete acquisitions and organic growth projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the crude oil and refined products that we gather, store, transport and handle.

The crude oil and refined products that we gather, store, transport and handle are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our refined products terminals and could require the construction of additional facilities to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws include federal and state laws that impose obligations related to air emissions, regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal, regulate discharges from our facilities into state and federal waters, including wetlands, establish strict liability for releases of oil into waters of the United States, impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities, relate to the protection of endangered flora and fauna and impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with

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discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, some of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the facilities where any wastes we generate are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Numerous governmental authorities, such as the Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. More stringent laws and regulations may be adopted in the future. We may not be able to recover all or any of these costs from insurance.

Climate change legislation or regulatory initiatives could result in increased operating costs and reduced demand for the services we provide.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Accordingly, the EPA adopted emissions limits for motor vehicles, which then triggered the development and adoption of construction and operating permit requirements under the Prevention of Significant Deterioration and Title V programs for certain stationary sources. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis. In December 2014, the EPA proposed additional amendments to its greenhouse gas reporting rule, which could add reporting requirements for additional facilities.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production in our areas of operation, which could adversely impact our business and results of operations.

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including

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those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in the crude oil transportation, storage, supply and logistics, refined products terminals and storage and NGL distribution and sales industries, including:

·                  damage to our facilities, vehicles and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

·                  inadvertent damage from construction, vehicles, farm and utility equipment;

·                  leaks of crude oil, NGLs and other hydrocarbons or losses of crude oil or NGLs as a result of the malfunction of equipment or facilities;

·                  ruptures, fires and explosions; and

·                  other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground storage tanks. In addition, although we are insured for environmental pollution resulting from certain environmental incidents, we may not be insured against all environmental incidents that might occur, some of which may result in toxic tort claims. If a significant incident occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.

We are subject to litigation risks that could adversely affect our operating results to the extent not covered by insurance.

Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as NGLs, refined products and crude oil. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.

Because our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates are likely to increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who

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invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at intended levels.

Debt we may incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities.

We have approximately $83.0 million of total indebtedness and $145.7 million available for future borrowings under our revolving credit facility as of December 31, 2014. Our future level of debt could have important consequences to us, including the following:

·                  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·                  our funds available for operations, future business opportunities and cash distributions to our unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

·                  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

·                  our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to our unitholders and value of our common units.

Our revolving credit facility limits our ability to, among other things:

·                  incur or guarantee additional debt;

·                  make distributions on or redeem or repurchase units;

·                  make certain investments and acquisitions;

·                  make capital expenditures;

·                  incur certain liens or permit them to exist;

·                  enter into certain types of transactions with affiliates;

·                  merge or consolidate with or into another company; and

·                  transfer, sell or otherwise dispose of our assets.

Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with, or obtain a waiver of, the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to terminate the remaining commitments under our revolving credit facility and declare the outstanding principal thereunder, together with accrued and unpaid interest, to be immediately due and payable. If

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the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Cyber-attacks and threats could have a material adverse effect on our operations.

Cyber-attacks may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. We currently are implementing our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material adverse effect on our operations or those of our customers.

The risk of terrorism, political unrest and hostilities in the Middle East or other energy producing regions may adversely affect the economy and our business.

Terrorist attacks, political unrest and hostilities in the Middle East or other energy producing regions may adversely impact the price and availability of crude oil, refined products and NGLs, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil and NGL supplies and markets, and our infrastructure or facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to gather and transport crude oil, refined products and NGLs if our means of transportation become damaged as a result of an attack. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.

Derivatives legislation adopted by Congress and rules and regulations promulgated thereunder by the CFTC could have an adverse impact on our ability to hedge risks associated with our business.

The Dodd-Frank Act was signed into law in 2010 and regulates derivative and commodity transactions, which include certain instruments used in our risk management activities.  The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the legislation. While many of the regulations are already in effect, the implementation process is still ongoing, and we cannot yet predict the ultimate effect of the regulations on our business.

In its rulemaking under the Dodd-Frank Act, the CFTC may finalize its regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied.  Once finalized, the position limits rule and its companion rule on aggregation may have an impact on our ability to hedge our exposure to certain commodities.  The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption, such as the end-user exception, to such requirements).  As the CFTC further designates swap contracts as required to be cleared and traded on a trading facility, the utility of exemptions such as the end-user exception will become even more important.  Our ability to rely on the end-user exception may impact the effectiveness of our hedging activities.

In addition, the Dodd-Frank Act and any new regulations could, among other things, significantly increase the cost of entering into derivative and commodity contracts (including from swap recordkeeping and reporting requirements), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, require greater collateral support (e.g., initial and variation margin) for derivative contracts, and potentially increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

Because the CFTC is still in the process of interpreting its regulations, it is possible that some of the derivative and commodity contracts used in our business may be treated differently in the future.  For example, the CFTC may further revise its definitions for spots, forwards, forwards with volumetric optionality, trade options, full requirements contracts and certain other contracts that may combine the elements of physical commodity trades and cash settlement, netting and book-outs.  If these contracts were classified as swaps, the costs of entering into these contracts will likely increase.

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Finally, under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in physical commodities markets traded in interstate commerce, including physical energy and other commodities, as well as financial instruments, such as futures, options and swaps.  The CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets.  Accordingly, the CFTC and the self-regulatory organizations (“SROs”), such as commodity futures exchanges, are continuing to develop their respective enforcement authorities and compliance priorities under the Dodd-Frank Act.  Given the novelty of the regulations under the Dodd-Frank Act, it is difficult to predict how these new enforcement priorities of the CFTC and the SROs will impact our business.  Should we violate the laws regulating hedging activities or regulations promulgated by the CFTC or any rules adopted by the SROs thereunder, we could be subject to CFTC enforcement action and material penalties and sanctions.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel and employees.

Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with energy industry experience. Competition for these persons in the energy industry is intense. For instance, given the overall demand for crude oil transportation services, qualified drivers of crude oil gathering and transportation trucks are in high demand. We may be unable to attract and retain enough qualified drivers to effectively service our customers. Additionally, given our size, we may be at a disadvantage, relative to our larger competitors, in the competition to attract and retain such personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Lonestar, JP Development and ArcLight, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.

CB Capital Holdings II, LLC and JP Energy GP LLC (two entities that are owned and controlled by certain members of management) and Lonestar own and control our general partner and its non-economic general partner interest in us. In addition, management owns an aggregate 4.8% limited partner interest in us and Lonestar owns a 51.3% limited partner interest in us. Although our general partner has a duty to manage us in a manner that it believes is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owners. Conflicts of interest may arise between CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar, JP Development and ArcLight and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including Lonestar, JP Development and ArcLight, over the interests of our unitholders. These conflicts include, among others, the following:

·                  neither our partnership agreement nor any other agreement requires CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar, JP Development or ArcLight to pursue a business strategy that favors us;

·                  our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

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·                  certain officers and directors of our general partner are officers or directors of affiliates of our general partner, including CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar and JP Development, and also devote significant time to the business of these entities and are compensated accordingly;

·                  affiliates of our general partner are not limited in their ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us, subject to the right of first offer that JP Development and ArcLight Fund V have granted us;

·                  except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

·                  our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

·                  our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce our operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of subordinated units to convert into common units;

·                  our general partner will determine which costs incurred by it are reimbursable by us;

·                  our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;

·                  our partnership agreement permits us to classify up to $30.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the incentive distribution rights;

·                  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

·                  our general partner intends to limit its liability regarding our contractual and other obligations;

·                  our general partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of our outstanding common units;

·                  our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including (i) the right of first offer granted to us by JP Development and ArcLight Fund V and (ii) the performance of one of the truck transportation agreements in our crude oil gathering and transportation business, each as described in greater detail in “Certain Relationships and Related Party Transactions”;

·                  our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

·                  our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity

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for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Affiliates of our general partner, including Lonestar, JP Development and ArcLight, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Neither our partnership agreement nor any other agreement will prohibit affiliates of our general partner, including Lonestar, JP Development and ArcLight, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, ArcLight Fund V is the majority owner of the general partner of another publicly traded master limited partnership in the midstream segment of the energy industry, which may compete with us in the future. In addition, Lonestar, JP Development, ArcLight and other affiliates of our general partner may acquire, construct or dispose of midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets, subject to the right of first offer that JP Development and ArcLight Fund V, have granted us. As a result, competition from affiliates of our general partner, including Lonestar, JP Development LP and ArcLight, could materially adversely impact our results of operations and distributable cash flow.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of distributable cash flow available to our unitholders.

Other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions, and our general partner has considerable discretion to establish cash reserves that would reduce the amount of available cash we distribute to unitholders.

Generally, our available cash is comprised of cash on hand at the end of a quarter plus cash on hand resulting from any working capital borrowings made after the end of the quarter less cash reserves established by our general partner. Our partnership agreement permits our general partner to establish cash reserves for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements), to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to unitholders. As a result, even when there is no change in the amount of distributable cash flow that we generate, our general partner has considerable discretion to establish cash reserves, which would result in a reduction in the amount of available cash we distribute to unitholders. Accordingly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders.  This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a

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unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

·                  whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

·                  our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

·                  our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

·                  our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any unitholder or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.

In the future, we may acquire or construct assets that are subject to regulation by the Federal Energy Regulatory Commission (“FERC”), and we may enter into leases with, or obtain permits or other authorizations from, the federal government that place citizenship requirements on our investors. In order to avoid (i) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on any assets that are subject to rate regulation by FERC or analogous regulatory body and (ii) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are United States citizens. Rate eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If you are not a person who meets the requirements to be a citizenship eligible holder and a rate eligible holder, you run the risk of having your units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if you are not a person who meets the requirements to be a citizenship eligible holder, you will not be entitled to voting rights.

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Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our distributable cash flow. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Lonestar, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are controlled by members of our management and by Lonestar. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be reduced because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management.

Even if holders of our common units are dissatisfied, they cannot remove our general partner without its consent.

Our unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 662/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. Our general partner and its affiliates own 56.1% of our common units and subordinated units. Also, if our general partner is removed without cause during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its non-economic general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of our general partner’s members to transfer their membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers of our general partner.

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Our general partner may transfer its incentive distribution rights to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its non-economic general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Lonestar or its affiliates, including JP Development, selling or contributing midstream assets to us, as Lonestar and its affiliates would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue additional units without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our revolving credit facility prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

·                  our unitholders’ proportionate ownership interest in us will decrease;

·                  the amount of distributable cash flow available for distribution on each unit may decrease;

·                  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

·                  the ratio of taxable income to distributions may increase;

·                  the relative voting strength of each previously outstanding unit may be diminished; and

·                  the market price of our common units may decline.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.

In some instances, our general partner may cause us to borrow funds under our revolving credit facility, from Lonestar or its affiliates or otherwise from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80.0% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner and its affiliates own approximately 22.2% of our common units. At the end of the subordination period (which could occur as early as September 30, 2015), assuming no additional issuances of common units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own approximately 56.1% of our common units.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:

·                  we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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·                  your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us.

There were 13,750,000 publicly traded common units as of March 2, 2015. In addition, our general partner and its affiliates own 56.1% of our common units and subordinated units. An investor may not be able to resell its common units at or above its acquisition price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including:

·                  our quarterly distributions;

·                  our quarterly or annual earnings or those of other companies in our industry;

·                  the loss of a large customer;

·                  announcements by us or our competitors of significant contracts or acquisitions;

·                  changes in accounting standards, policies, guidance, interpretations or principles;

·                  general economic conditions;

·                  the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

·                  future sales of our common units; and

·                  other factors described in these Risk Factors.

Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that

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would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee will have the same rights as our general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

We will incur increased costs as a result of being a publicly traded partnership.

We have limited history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, Section 404 of the Sarbanes-Oxley of 2002 and related rules subsequently implemented by the Securities and Exchange Commission and the New York Stock Exchange have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this matter.  Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash flow available for distribution to you. Therefore, if we were treated as a corporation for federal income tax

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purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for federal income tax purposes. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

Our unitholders’ share of our income is taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder is treated as a partner to whom we allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash flow available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders (including holders of our subordinated units) because the costs will reduce our distributable cash flow.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

An investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-United States persons raises issues unique to them. For example, virtually all

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of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and is taxable to them. Distributions to non-United States persons are reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons are required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult a tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We have adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and our unitholders, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and certain of our unitholders.

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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and we could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in every state in the continental United States. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

We believe that we have satisfactory title to all of the assets that we own. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us, we believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

Our general partner maintains its headquarters in Irving, Texas. We also have regional offices located in Houston, Texas, Tulsa, Oklahoma and Gurnee, Illinois. The current lease of our general partner’s headquarters expires in 2019. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.

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ITEM 3. LEGAL PROCEEDINGS.

The information required for this item is provided in “Note 15 — Commitments and Contingencies” included in our audited consolidated financial statements in Part IV, Item 15 of this report, which is incorporated herein by reference.

ITEM 4. MINE SAFTEY DISCLOSURES.

None.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our common limited partner units are traded of the New York Stock Exchange (“NYSE”) under the symbol “JPEP.” Initial trading of our common units commenced on October 2, 2014. Accordingly, no market for our common units existed prior to that date. On October 7, 2014, we closed our IPO at a price to the public of $20.00 per common unit.

The following table sets forth the quarterly high and low sales prices per common unit, as reported by the NYSE, and the quarterly cash distributions for the indicated period:

(1)                                 Represents the initial pro rata distribution of our minimum quarterly distribution for the period from October 7, 2014 to December 31, 2014.

Holders

As of March 2, 2015, the market price for our common units was $14.75 per unit and there were approximately 65 unitholders of record of our common units. There are 70 record holders of our subordinated units. There is no established public trading market for our subordinated units.

Securities Authorized for Issuance under Equity Compensation Plans

In connection with the completion of our IPO, our general partner adopted the JP Energy Partners LP 2014 Long-Term Incentive Plan. Please read “Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” which is incorporated by reference into this Item 5.

Distributions of Available Cash

General. Our 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, as determined by our general partner.

Definition of Available Cash. Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

·                  less, the amount of cash reserves established by our general partner to:

·                  provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);

·                  comply with applicable law, any of our debt instruments or other agreements; or

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·                  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

·                  plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

Minimum Quarterly Distribution. We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.3250 per unit, or $1.30 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

Incentive Distribution Rights. As our quarterly distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner, as the holder of the IDRs, becomes entitled to increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. See Note 13 to our audited consolidated financial statements for additional information.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Unitholder Return Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933, as amended (the “Securities Act”) or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), except to the extent we specifically incorporate it by reference into such filing.

The following performance graph compares the cumulative total unitholder return on our common units as traded on the NYSE with the Standard & Poor’s 500 Stock Index (the “S&P 500”), and the Alerian MLP Index (“MLP Index”). It is assumed that (i) $100 was invested in our common units at $19.11 per unit (the closing price at the end of our first trading day), the S&P 500, and the MLP Index on October 2, 2014 (our first day of trading) and (ii) distributions were reinvested on the relevant payment dates. The following performance graph is historical and not necessarily indicative of future price performance.

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ITEM 6. SELECTED FINANCIAL DATA.

The table set forth below presents, as of the dates and for the periods indicated, our selected historical consolidated financial and operating data. The historical financial data presented as of December 31, 2014, 2013, 2012 and 2011 and for the years ended December 31, 2014, 2013, 2012, and 2011 have been derived from our audited historical consolidated financial statements. The historical financial data presented as of December 31, 2010 and for the period for May 5, 2010 (date of inception) to December 31, 2010 is derived from our unaudited historical consolidated financial statements.

On February 12, 2014, we acquired certain assets from JP Development. Because we and JP Development are both affiliates of ArcLight, this was a transaction between commonly controlled entities and we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the acquired assets at JP Development’s historical carryover basis instead of reflecting the fair market value of assets and liabilities of the acquired assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the acquired assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements.”

The following table should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements included elsewhere in this document.

The following table presents Adjusted EBITDA and adjusted gross margin, financial measures that are not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). For a discussion of how we derive these measures and a reconciliation of Adjusted EBITDA and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP and a discussion of how we use Adjusted EBITDA and adjusted gross margin to evaluate our operating performance, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Adjusted EBITDA and adjusted gross margin.”

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(1)                                 Our historical consolidated financial and operating data for the years ended December 31, 2013 and 2012 have been retrospectively adjusted for the JP Development Dropdown. Please read Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements.”

(2)                                 In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(3)                                 Adjusted gross margin and Adjusted EBITDA are financial measures that are not presented in accordance with GAAP. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Adjusted EBITDA and adjusted gross margin.”

(4)                                 Represents the average daily throughput volume in our crude oil pipelines and storage segment, the average daily sales volume in our crude oil supply and logistics segment, the average daily throughput volume in our refined products terminals and storage segment and the average daily sales volume in our NGL distribution and sales segment.

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ITEM 7. 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 is provided as a supplement to, and should be read in conjunction with, our historical consolidated financial statements and the notes thereto included elsewhere in this document.

Overview

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, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:

·                  owning, operating and developing midstream assets serving two of the most prolific shale plays in the United States, as well as serving key crude oil, refined product and NGL distribution hubs;

·                  providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and

·                  operating one of the largest propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.

We are focused on growing our business through organic development, acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs.

General Trends and Outlook

Our business is subject to the key trends discussed below. We have based our expectations on assumptions made by us and on the basis of information currently available to us. To the extent our underlying assumptions about our interpretation of available information prove to be incorrect, our actual results may vary from our expected results.

Production

Over the past several years, there has been a fundamental shift in crude oil production in the United States towards unconventional resources. According to the EIA, this includes crude oil produced from shale formations, tight gas and coal beds. The emergence of unconventional crude oil plays, such as in the Permian Basin, and advances in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of crude oil from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale production. The development of these unconventional sources has offset declines in other, more traditional hydrocarbon supply sources, which has helped meet growing demand and lowered the need for imported crude oil. While crude oil production in the United States has been strong in recent years, the steep decline in crude oil prices has reduced the incentive for producers to expand production. Several major producers have reported that they plan to reduce their capital expansion budgets, and several oilfield services companies have announced reductions in staffing. Various media outlets have reported that, with prices at current levels, it may become uneconomical to drill new crude oil wells in certain basins. If crude oil prices remain low, declines in crude oil production may adversely impact volumes in our crude oil supply and logistics segment and crude oil pipelines and storage segment.

Production of Refined Products

Access to lower cost crude oil supplies has enabled inland refineries to produce refined petroleum products at a cost that allows them to compete over a much broader geographic area with supply from refineries located on the Gulf Coast. This dynamic has significantly diminished the flow of crude oil from the Gulf Coast to the Midwest and increased the flow of refined petroleum products from the Midwest to the Gulf Coast. We believe the changing dynamics of crude oil production may offer opportunities to grow the throughput and value of our refined products terminals by completing projects to connect them to additional, less-expensive sources of product supply.

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In the third quarter of 2014, we discovered that our product measurement and quality control processes at our refined products terminal in North Little Rock, Arkansas were resulting in excessive product gains for JP Energy. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we returned a certain amount of refined products to the majority of our customers in the fourth quarter of 2014. We have recorded a charge of $2.3 million for the year ended December 31, 2014, of which $2.1 million represents the value of refined products we have returned to our customers and $0.2 million represents the estimated value of refined products we will return to our customers.

We believe it is reasonably likely that the new processes and procedures that we are undertaking will result in a decrease in revenues from product sales in our refined products terminals and storage segment in future periods relative to historical periods, although this reduction may be partially offset by an operational excellence initiative that we are undertaking at both of our refined products terminals.

Supply of Crude Oil Storage Capacity

An important factor in determining the value of our crude oil storage capacity and the rates we are able to charge for new contracts or contract renewals is whether a surplus or shortfall of crude oil storage capacity exists relative to the overall demand for crude oil storage services in a given market area. We currently have a long-term contract with the user of our crude oil storage capacity in Cushing, Oklahoma that has a remaining term of approximately 2.5 years as of December 31, 2014. We believe the demand for crude oil storage capacity in our market area will remain strong because of rising inland United States and Canadian production and the integral role that the Cushing interchange plays in facilitating the transfer of crude oil to refiners on the Gulf Coast.

Seasonality

The financial and operational results in our NGL distribution and sales segment are impacted by the seasonal nature of propane demand. The retail propane business is seasonal because of increased demand during the months of November through March primarily for the purpose of providing heating in residential and commercial buildings. As a result, the volume of propane we sell is at its highest during our first and fourth quarters and is directly affected by the severity of the winter. However, our cylinder exchange business sales volumes provide us increased operating profits during our second and third quarters, which reduces overall seasonal fluctuations in the financial and operational results in our cylinder exchange business and our NGL sales business. For the year ended December 31, 2014, we sold approximately 59% of the propane volumes in our cylinder exchange and NGL sales businesses during the first and fourth quarters of the year.

The butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

Weather

Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Accordingly, the volume of propane used by our customers for this purpose is affected by the severity of winter weather in the regions we serve and can vary substantially from year to year while general economic conditions in the United States and the wholesale price of propane can have a significant impact on the correlation between weather and customer demand. For the twelve months ended December 31, 2014, the weather in Texas, Oklahoma, New Mexico, Arizona, Arkansas, Kansas and Missouri, the seven states in which our NGL sales business operates, was 4% warmer than the average temperature of the prior year as measured by the number of heating degree days reported by the NOAA. If these seven states were to experience a cooling trend, we could expect demand for propane to increase, which could lead to greater sales and income.

Commodity Prices

We are exposed to volatility in crude oil, refined products and NGL commodity prices. We manage such exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.

We do not have direct exposure to commodity price changes in our crude oil pipelines and storage segment. In our crude oil supply and logistics business, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open

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positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using financial swaps. In our cylinder-exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a large majority of the forecasted volumes under our long-term contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. In our NGL transportation business, we do not take title to the products we transport and, therefore, have no direct commodity price exposure to the price of volumes transported.

Interest Rates

The credit markets experienced near-record low interest rates in recent years. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our current or prospective financing costs to increase accordingly.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements for consistency and trend analysis. These metrics include volumes, revenues, cost of sales, excluding depreciation and amortization, operating expenses, Adjusted EBITDA and distributable cash flow.

·                  Volumes and revenues.

·                  Crude oil pipelines and storage.  The amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a substantial majority of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.

·                  Crude oil supply and logistics.  The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.

·                  Refined products terminals and storage.  The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals, which we believe are strategically located to take advantage of infrastructure development opportunities resulting from growing markets.

·                  NGL distribution and sales.  The amount of revenue we generate from our NGL distribution and sales segment depends on the gallons of NGLs we sell through our cylinder exchange and NGL sales businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transport those gallons for our customers. Revenues in

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this segment are also impacted by changes in the market price of commodities that we pass through to our customers.

·                  Cost of sales, excluding depreciation and amortization.  Our management attempts to minimize cost of sales, excluding depreciation and amortization, in order to enhance the profitability of our operations. Cost of sales, excluding depreciation and amortization, includes the costs to purchase the product and any costs incurred to transport the product to the point of sale and to store the product until it is sold. We seek to minimize cost of sales, excluding depreciation and amortization, by attempting to acquire the products which we use in each of our segments at times and prices which are most optimal based on our knowledge of the industry and the regions in which we operate.

·                  Operating expenses.  Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised of payroll, wages and benefits, utility costs, fleet costs, repair and maintenance costs, rent, fuel, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.

·                  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).

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:

·                  our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;

·                  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;

·                  our ability to incur and service debt and fund capital expenditures; and

·                  the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Adjusted EBITDA 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.

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