10-K

DisposalGroupIncludingDiscontinuedOperationConsiderationDisposalGroupIncludingDiscontinuedOperationConsideration

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2015

or

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

For the transition period from   to

Commission file number 001-36647

JP ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	27-2504700
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)

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:

Title of each class	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

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   No ☒

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   No ☒

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

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

Indicate by check mark 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. 

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.

Large accelerated filer ☐	Accelerated filer ☒
Non-accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2015, was $187,527,418. The aggregate market value was computed by reference to the last sale price of the registrant's common units on the New York Stock Exchange on June 30, 2015.

As of February 22, 2016, the Registrant had 18,467,032 common units and 18,126,511 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

TABLE OF CONTENTS

	Page
PART I
ITEMS 1. BUSINESS	3
ITEM 1A. RISK FACTORS	18
ITEM 1B. UNRESOLVED STAFF COMMENTS	48
ITEM 2. PROPERTIES	48
ITEM 3. LEGAL PROCEEDINGS	48
ITEM 4. MINE SAFETY DISCLOSURES	48
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	49
ITEM 6. SELECTED FINANCIAL DATA	51
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	53
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	79
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	80
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	80
ITEM 9A. CONTROLS AND PROCEDURES	80
ITEM 9B. OTHER INFORMATION	82
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	83
ITEM 11. EXECUTIVE COMPENSATION	89
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	98
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	101
ITEM 14. PRINCIPAL ACCOUNT FEES AND SERVICES	104
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	105

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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,” “estimate,” “forecast,” “target,” “project,” “assume,” “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, demand for and production of, 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;

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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,natural gas liquids, refined products and natural gas;

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

a deterioration of the credit and capital markets;

volatility of fuel prices;

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

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

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

environmental hazards;

industrial accidents;

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

fires, explosions or other accidents;

the effects of future litigation; and

other factors discussed elsewhere in this Annual Report and in our other current and periodic reports filed with the Securities and Exchange Commission (the “SEC”).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We disclaim any obligation to and do not intend to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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ITEM 1. 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. In the fourth quarter of 2015, we combined our formerly reported crude oil supply and logistics segment into our crude oil pipelines and storage segment.  As a result, our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) 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. Our primary business strategy is 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; and

· 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 growth in hydrocarbon production across the United States.

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 highly prolific areas, including the Permian Basin and Eagle Ford shale, and provide us with a footprint to increase our volumes if 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 operations within our crude oil pipelines and storage 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 26 third-party acquisitions and numerous organic capital projects. These include the acquisitions of:

· the Silver Dollar Pipeline System in October 2013;

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

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

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

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

· our cylinder exchange business in June 2012; and

· 18 separate wholesale and retail propane businesses from July 2010 through May 2015.

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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 pipelines and storage segment, and NGLs and refined products in our NGL distribution and sales segment. A portion of our margin related to the purchase and sale of crude oil in our crude oil pipelines and storage 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 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 ArcLight

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 and (ii) a 55.7% limited partner interest in us creates a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business.

Right of First Offer

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 Republic is for a period of eighteen months from the closing of our IPO.

Republic owns and operates certain crude oil midstream assets servicing producers in the Eagle Ford shale region. Republic’s initial assets consist of a 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 that will deliver batched volumes from the central delivery terminal to major long-haul takeaway pipelines. We have agreed to perform certain commercial services for Republic, including working with producers to provide crude oil solutions from the wellhead to end markets.

Our Assets and Operations

Crude Oil Pipelines and Storage

Silver Dollar Pipeline System.  The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Spraberry and Wolfcamp formations in the Midland Basin. The system currently consists of approximately 148 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 barrels per day and three 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 eight years and contains an acreage dedication related to crude oil production from approximately

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110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately four years and contains a minimum volume commitment that was amended in March 2015 and again in August 2015 to significantly increase the volumes committed thereunder. A third significant contract has a remaining term of approximately nine 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 serves production from the Spraberry and Wolfcamp formations in the Midland Basin within Crockett, Reagan, Glasscock, Sterling, Irion and Schleicher Counties, Texas, liquids-rich plays being developed by several large oil and gas producers. The Spraberry and Wolfcamp are stacked formations with multiple horizontal targets that can be accessed with a single well. As of December 2015, the Silver Dollar Pipeline System is connected to producers that control approximately 330,000 acres in Crockett, Reagan, Glasscock, Sterling, Irion and Schleicher Counties, Texas, and we are in 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.

			Throughput as of the
			Year Ended
Length	Capacity	Storage Capacity	December 31, 2015	December 31, 2014
148 miles	130,000bpd	140,000 barrels	28,246bpd	20,868bpd

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 pipeline expansion. In November 2014, a second connection was made to Oxy Centurion’s Cline Shale pipeline to give Silver Dollar a second delivery location. 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.

In February 2015, we signed a 10-year fee based gathering agreement with Discovery Natural Resources LLC (“Discovery”) to construct and operate an extension of our Silver Dollar Pipeline system into the core of the Midland Basin. The agreement with Discovery is supported by a dedication of approximately 53,000 acres in Reagan, Glasscock, Sterling and Irion Counties. In addition to pipeline gathering, we also provide crude oil trucking, marketing and related services for Discovery. The gathering system extension consists of approximately 51 miles of pipeline, extending from southern Reagan County north into Glasscock County across the Midland Basin. In September 2015, we completed Phase I of the project, which included the construction and commissioning of 32 miles of pipeline and associated truck and measurement facilities. Phase II of the project was completed in January 2016.

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

In April 2015, we announced that we have executed an interconnection agreement with an affiliate of Magellan Midstream Partners, L.P. (“Magellan”) to connect our Silver Dollar Pipeline System to Magellan’s Longhorn pipeline at the Barnhart Terminal in Crockett County, Texas. The interconnection provides producers with a third takeaway option from the Silver Dollar Pipeline System and direct access from the core of the Midland Basin to end markets in Houston. The connection was completed and began service in September 2015. As part of the Magellan project, we also added 30,000 barrels of crude oil storage which further increased the total crude oil storage capacity on the Silver Dollar Pipeline to 140,000 barrels.

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In our crude oil pipelines business, we purchase crude oil from a producer or supplier at a designated receipt point on our Silver Dollar Pipeline System at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, allowing us to lock in a fixed margin that is in effect economically equivalent to a transportation fee. These transactions account for substantially all of the Adjusted EBITDA we generate on our Silver Dollar Pipeline System.

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 an escrow account, with an initial expiration in August 2017. 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 49-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), and purchases of material. These services are provided to us at a monthly base rate and we are permitted to request additional

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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 pipelines and storage segment also 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 future crude oil production growth, including the Permian Basin, Eagle Ford shale, and the Texas Panhandle. We own and operate a fleet of approximately 74 crude oil gathering and transportation trucks and approximately four crude oil truck injection stations and terminals. 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 business 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 business 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 grow our future operations in the Permian Basin, Eagle Ford shale and the Texas Panhandle.

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 business generates substantial revenues and cost of products sold as a result of the significant volume of crude oil bought and sold. While the absolute price levels of crude oil significantly impact revenues and cost of products sold, such price levels normally do not bear a relationship to gross profit for crude oil sales generated under buy/sell contracts. As a result, period-to-period variations in revenues and cost of products sold are not generally meaningful in analyzing the variation in gross profit for our crude oil supply business.

We mitigate the commodity price exposure of our crude oil supply and logistics business 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. 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.

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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

· 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:

	Shell					Approximate Average Throughput
	Storage					(barrels per day) for the
	Capacity	Loading	Number		Mode of	Year Ended	Year Ended
						December 31,	December 31,
Terminal Location	(bbls)	Lanes	of Tanks	Supply Source	Redelivery	2015	2014
Little Rock, AR	550,000	8	11	Pipeline, Rail and Truck	Truck	41,018	44,415
Caddo Mills, TX	770,000	5	10	Pipeline and Truck	Truck	21,057	19,444

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

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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. On February 15, 2016, we announced capital projects to increase ethanol receipts via unit trains on our rail spur and connect the terminal to Magellan’s Fort Smith – Little Rock pipeline which will provide access to both Gulf Coast and Mid-Continent refineries.  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 six 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

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 98,900 customers through our distribution network of 39 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 18 propane franchises to expand our market presence within our operating region in Texas, Oklahoma, New Mexico, Arizona, Arkansas, Kansas 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 135 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

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fixed cost-plus fee for propane sold. Another subsidiary, Alliant Gas, serves 26 communities in Texas and two communities in Arizona through regulated central distribution systems pursuant to long-term contracts. Net customer turnover at Alliant Gas is nearly zero.

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

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

Product supply.  We utilize 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 standard agreements with one-year terms and standard commercial provisions.

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, 2015 and December 31, 2014, approximately 88% and 87%, respectively, of our propane supply was purchased under supply agreements, which typically have a term of one year, and the remainder was purchased 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 substantially all fixed-price contracts.

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 approximately 21,000 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, 2015, we sold or exchanged approximately 5.1 million propane cylinders containing approximately 18.3 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 for portable propane cylinders and our expansion in the western United States.

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, 2015 and December 31, 2014, we distributed 49% and 54%, respectively, of our propane volumes in our cylinder exchange business under long-term agreements and the remaining 51% and 46%, respectively, under one-month contracts or on a spot/demand basis. As of December 31, 2015, our contracts had a weighted average remaining term of approximately 0.9 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 a majority of fixed-price contracts.

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Cylinder production cycle.  We own eight production facilities strategically located in Alabama, Illinois, Michigan, Missouri, Nevada, Oregon, 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 52 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 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. Concurrent with our crude oil supply and transportation fleet, we utilize our proprietary CAST software in our NGL transportation trucks, which we believe provides us with a competitive advantage by allowing us to offer our customers a differentiated level of service. For the years ended December 31, 2015 and December 31, 2014, our NGL transportation trucks transported approximately 344,763 gallons per day and 311,733 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. Additionally, 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 crude oil pipeline, transportation, gathering and storage companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our competitors in our crude oil pipelines and storage segment include Blueknight Energy Partners, L.P., Enterprise Products Partners L.P., Medallion Midstream LLC, NGL Energy Partners L.P., Occidental Petroleum Corporation, Plains All American Pipeline, L.P., Rose Rock Midstream, L.P., SemGroup Corporation, and Sunoco Logistics.

Refined products terminals and storage.  Our refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas compete with other 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, Delek Logistics Partners LP and HWRT Oil Company, LLC. In Dallas, Texas, the market served by our Caddo Mills, Texas terminal, these competitors include Valero Energy Corporation, Delek Logistics Partners, LP, Magellan Midstream Partners LP and Flint Hills Resources LP.

NGL distribution and sales.  In addition to competing with suppliers of other energy sources such as natural gas, our NGL distribution and sales segment competes with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. The large, full-service multi-state marketers we compete with include Ferrellgas, L.P. and AmeriGas Partners, L.P. Each of our customer service centers operates in its own competitive environment because retail marketers tend to be located in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

Customers

We rely on a limited number of customers for a substantial portion of our revenues. Occidental Energy Marketing, Inc. accounted for 10% or more of our total revenue for the year ended December 31, 2015, at approximately 37%.

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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, 2015, we sold approximately 68.0 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 41% in the second and third quarters of 2015 and 59% in the first and fourth quarters of 2015.

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 casualty, property, and environmental 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.

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 Department of Transportation (“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

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subject to the regulatory oversight of the Texas Railroad Commission and the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), whose pipeline safety regulations are described in the section below.

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. In October 2015, PHMSA proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempted pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management provisions. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a separate regulatory proposal in July 2015 that would impose further pipeline incident prevention and response measures on pipeline operations. While we expect such regulatory changes to allow us time to become compliant with new requirements, once finalized, costs associated with compliance may have a material effect on our operations.

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.

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

Management believes that the policies and procedures currently in effect at all of our propane gas systems are consistent with industry standards and are in compliance with applicable law. Due to our ownership and control of these gas utility companies, we are required to notify FERC of our status as a holding company. We 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,

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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 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

The 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.

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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 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 and Flaring

Increased regulation of hydraulic fracturing and flaring of natural gas 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 or flaring 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 and, due to the lack of natural gas transportation infrastructure in certain areas, sometimes also results in flaring of natural gas produced in association with crude oil production. Hydraulic fracturing and flaring are 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 or flaring 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 or flaring could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

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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 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 October 2015, the EPA finalized additional amendments to its greenhouse gas reporting rule, which added pre-reporting requirements for additional facilities. And in August 2015, the EPA proposed additional regulations to reduce emissions of methane and volatile organic compounds from the oil and gas sector.

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. In addition, in December 2015, over 190 countries, including the United States, reached an agreement to address GHG emissions.

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. 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 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 “JP Energy Partners,” “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.

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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 February 22, 2016, our general partner and its affiliates have approximately 737 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.

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 $11.9 million per quarter, or $47.6 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, demand for, and production of, 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;

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· 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;

· competitive conditions in our industry; and

· changes in the long-term supply of, and demand for, oil, natural gas liquids, refined products and natural gas.

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;

· the amount of corporate overhead support provided by our general partner, if any; and

· other business risks affecting our cash levels.

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A sustained decrease in demand for, or production of, 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, or production of crude oil, refined products or NGLs include:

· lower demand by consumers for refined products, NGLs or crude oil as a result of adverse economic conditions, an increase in the market price of crude oil, NGLs, 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, NGLs or natural gas or for other reasons; and

· fluctuations in the demand for crude oil, such as those caused by refinery downtime or shutdowns, lower crack spreads or lower consumer demand for petroleum products.

Benchmark crude oil prices declined significantly during 2015 and early 2016. As a result, many of the companies that produce oil and gas have announced that they are reducing capital expenditures for 2016. Such reduced expenditure levels, coupled with the high decline rates for many horizontal wells in shale resource plays, could lead to a substantial decrease in overall North American oil production. Other factors that could adversely impact production include reduced capital market access, increased capital raising costs for producers or adverse governmental or regulatory action. In turn, such developments could lead to reduced throughput on our pipelines, which, depending on the level of production declines, could have a material adverse effect on our business.

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 as little as 30 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 pipelines and storage segment either have terms as short as one month or have evergreen provisions and are cancellable on as little as 30 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 and could set contracts aside in the event of bankruptcy.

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.

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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 and storage 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.

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 depend on the level of oil production from 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 in this segment, 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 and overall crude oil production 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 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;

· basis differentials, transportation costs and other expenses impacting a producer’s net-back price;

· 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.

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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 and our sales and transportation volumes in our crude oil pipelines and storage segment, our revenue and cash flow could be reduced and our ability to make cash distributions to our unitholders could be adversely affected.

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

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

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 production from the Spraberry and Wolfcamp formations 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, aggregate crude oil production from the area in close proximity to our pipeline 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 pipelines and storage operations involve market and regulatory risks.

As part of our crude oil pipelines and storage 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 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;

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· 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. Occidental Energy Marketing, Inc. accounted for 10% or more of our total revenue for the year ended December 31, 2015, at approximately 37%. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms or at all. In addition, these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. Furthermore, our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Midstream capacity constraints and interruptions could impact our operations.

We rely on various midstream facilities and systems in connection with our crude oil pipelines and storage 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 pipelines and storage 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 pipelines and storage 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 pipelines and storage 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 pipelines and storage 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

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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 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 transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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

The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Conversely, a backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered for future delivery are expected to be lower. Accordingly, a backwardated market can negatively impact the demand for crude oil storage. If the forward market for crude oil is backwardated at times when we are renewing our crude oil storage contract or entering into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.

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

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

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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.

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 currently supplied by the TEPPCO Pipeline and is expected, in the future, to also be supplied by Magellan’s Fort Smith Pipeline, while our Caddo Mills terminal is supplied by the Explorer Pipeline. Reduced or interrupted throughput on these pipelines or outages at terminals with which our refined products terminals share interconnects because of weather or other natural events, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver refined products to our customers from our terminals or receive products for storage at our terminals, which could adversely affect our cash flows and revenues. In addition, in the event that one of the pipelines depended upon by either of our refined products terminals modifies its tariff to discontinue service for one or more of the products throughput at our terminals, we will have to discontinue selling or secure an alternate supply of such product. This could have a material adverse impact on the throughput volumes and revenues of our refined products terminals and storage segment.

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

Our refined products terminals and storage assets are generally long-lived assets. Our North Little Rock terminal has been in service for approximately 36 years, and our Caddo Mills terminal has been in service for approximately 31 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, 2015, 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 2015 the average temperature in the seven states in which we operate was 5% warmer than the average temperature of the prior year, 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, 2015, 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

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

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

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

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

During the year ended December 31, 2015, we purchased 70% 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

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

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

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

Risks of nonpayment and nonperformance by customers, including producers, are significant considerations in our business.  Although we have credit risk management policies and procedures that are designed to mitigate and limit our exposure in this area, there can be no assurance that we have adequately assessed and managed the creditworthiness of our existing or future counterparties, that there will not be an unanticipated deterioration in their creditworthiness or unexpected instances of nonpayment or nonperformance or that they will try to renegotiate contractual terms, all of which could have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We may be asked by third parties to provide additional credit support for certain of our crude oil purchases.

We rely on letters of credit under our revolving credit facility to purchase crude oil for our supply and logistics business.  Any changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to require additional support for our obligations, such as letters of credit or other forms of security, which would increase our operating costs and impact our ability to purchase crude oil or capitalize on market opportunities.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 third parties require additional credit support from us.

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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. JP Development recently divested of its existing assets to third parties after complying with the terms of the Right of First Offer Agreement. 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 inventory of suitable assets, their willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and JP Development and ArcLight Fund V are under no obligation to accept any offer that we may choose to make in response to any notice by JP Development or ArcLight Fund V of their intent to transfer assets. In addition, certain of the assets

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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 have in the past and may in the future 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.

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These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, some of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the facilities where any wastes we generate are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Numerous governmental authorities, such as the Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply 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 pre-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 October 2015, the EPA finalized additional amendments to its greenhouse gas reporting rule, which added reporting requirements for additional facilities. And in August 2015, the EPA proposed additional regulations to reduce emissions of methane and volatile organic compounds from the oil and gas sector.

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. In additions, in December 2015, over 190 countries, including the United States, reached an agreement to address GHG emissions.

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. 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, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects,

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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.

Our operations are subject to regulation by state and local regulatory authorities. Changes to or additional regulatory measures adopted by such authorities could adversely affect our results of operations and our ability to make cash distributions to unitholders.

Services provided by our gathering systems are subject to ratable-take and common purchaser statutes and complaint-based regulation by state regulatory authorities, such as the Texas Railroad Commission.  Ratable-take statutes generally require gatherers to take without undue discrimination crude oil production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer.  Complaint-based regulation allows oil producers to file complaints with state regulators in an effort to resolve grievances relating to access to oil gathering pipelines and rate discrimination.  These statutes could restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil.

Our pipelines do not provide interstate transportation services that are subject to regulation by FERC; however, a change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets, which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our crude oil pipeline facilities are not subject to regulation by FERC under the Interstate Commerce Act (the “ICA”) because we do not provide interstate transportation service or have been exempted from FERC regulation.  However, if circumstances change as to the use of our pipelines or FERC’s policies, services provided by our facilities could become subject to regulation by FERC under the ICA.  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.”  The regulations require operators to:

· Perform ongoing assessments of pipeline integrity;

· Identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

· Improve data collection, integration, and analysis;

· Repair and remediate the pipeline, as necessary; and

· Implement preventive and mitigation actions.

The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed 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, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violations of the pipeline safety laws and regulations that occur after January 3, 2012 to

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$200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

PHMSA has also proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management requirements. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA has also issued a separate regulatory proposal that would impose pipeline incident prevention and response measures on pipeline operators.  The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow.

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

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

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

Our operations are subject to all of the risks and hazards inherent in the crude oil transportation and storage, 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.

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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 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 $162.0 million of total indebtedness and $86.9 million available for future borrowings under our revolving credit facility as of December 31, 2015. 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.

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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;

· post letters of credit to counterparties in support of our business activities;

· 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 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.

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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.

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.

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

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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. 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 4.7% limited partner interest in us and Lonestar owns a 51.0% 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;

· 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;

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· 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, without limitation, the right of first offer granted to us by JP Development and ArcLight Fund V 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

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

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.

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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 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

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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.

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.

Our general partner is under no obligation to provide additional corporate overhead support.  The amount of future support, if any, will be determined by our general partner in its sole discretion.

In 2015, our general partner provided corporate overhead support by declining to seek reimbursement for certain expenses relating to the Partnership for which it was entitled to be reimbursed, which increased the amount of cash we had available for distribution.  Our general partner is under no obligation to provide additional corporate overhead support in the future.  Any reductions in such support 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 55.7% 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

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eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

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

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

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

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

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

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

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;

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· 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 22.0% of our common units. At the end of the subordination period, 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 55.7% 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

· 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.

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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 18,467,032 publicly traded common units as of February 22, 2016. In addition, our general partner and its affiliates own 55.7% 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 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

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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 being 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 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 U.S. federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S.  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 U.S. 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 U.S. 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 U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. 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. Several states have subjected, or 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 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.

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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 U.S. 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, members of Congress and the President have periodically considered substantive changes to the existing U.S. 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 U.S. federal income tax purposes. In addition, the U.S. Department of Treasury and the IRS have issued proposed regulations (the “Proposed Regulations”) regarding "qualifying income" under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended (the “Code”). The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income; however, the Proposed Regulations do not specifically address retail sales of propane. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income and do not specifically address retail sales of propane, we believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Internal Revenue Code. If the regulations in their final form were to treat any portion of our income we treat as qualifying income as non-qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations. The U.S. Department of Treasury and the IRS are considering comments from industry participants regarding the standards set forth in the Proposed Regulations.

Any modification to the U.S. 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 U.S. 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.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

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 U.S. 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 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 promulgated under the Internal Revenue Code (“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.

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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 aspects of our proration method, 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 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 U.S. Department of Treasury and the IRS recently issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could 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 U.S. 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 U.S. 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 in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss allocated to our unitholders. It also could affect the amount of 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 U.S. federal income tax purposes.

We will be considered to have technically terminated our partnership for U.S. 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

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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 U.S. federal income tax purposes, but instead we would be treated as a new partnership for U.S. 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 U.S. federal income taxes, our unitholders are likely 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 are likely 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.

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.

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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 on 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:

	Price Range				Distribution per
Quarterly Period	High		Low		common unit
2015
Fourth Quarter	$	8.95	$	3.91	$	0.3250
Third Quarter		13.94		5.25		0.3250
Second Quarter		15.00		10.75		0.3250
First Quarter		15.52		10.75		0.3250
2014
Fourth Quarter (from October 2, 2014)	$	20.71	$	10.55	$	0.3038	(1)

(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 February 22, 2016, the market price for our common units was $4.17 per unit and there were approximately 61 unitholders of record of our common units. There are 76 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

For information regarding our Equity Compensation 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

The information required for this item is provided in “Note 5 – Acquisitions and Dispositions”, included in our audited consolidated financial statements in Part IV, Item 15 of this report, which is incorporated herein by reference.

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

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reinvested on the relevant payment dates. The following performance graph is historical and not necessarily indicative of future price performance.

	10/2/2014		12/31/2014		6/30/2015		12/31/2015
JP Energy Partners	$	100.00	$	64.00	$	71.29	$	28.91
S&P 500		100.00		105.79		106.01		105.02
Alerian MLP Index		100.00		87.43		75.54		55.15

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, 2015, 2014, 2013, 2012 and 2011 and for the years ended December 31, 2015, 2014, 2013, 2012, and 2011 have been derived from our audited historical consolidated 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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	Year Ended December 31,
	2015		2014		2013		2012		2011
	($ in thousands, except unit data)
Statement of Operations Data:
Total revenue	$	680,585	$	726,154	$	390,869	$	204,391	$	67,156
Costs and expenses:
Cost of sales, excluding depreciation and amortization		527,476		605,682		276,804	$	151,478		49,048
Operating expense		69,377		65,584		57,728		26,292		9,584
General and administrative		45,383		46,362		44,488		20,785		6,053
Depreciation and amortization		46,852		40,230		30,987		12,941		2,841
Goodwill impairment		29,896		—		—		—		—
Loss on disposal of assets, net		909		1,137		1,492		1,142		68
Operating loss		(39,308)		(32,841)		(20,630)		(8,247)		(438)
Other income (expense):
Interest expense		(5,375)		(8,981)		(8,245)		(3,249)		(633)
Loss on extinguishment of debt		—		(1,634)		—		(497)		(95)
Other income, net		1,732		8		887		320		—
Loss from continuing operations before income taxes		(42,951)		(43,448)		(27,988)		(11,673)		(1,166)
Income tax expense		(754)		(300)		(208)		(222)		(35)
Net loss from continuing operations		(43,705)		(43,748)		(28,196)		(11,895)		(1,201)
Net income (loss) from discontinued operations (1)		(14,951)		(9,275)		13,975		3,507		—
Net loss	$	(58,656)	$	(53,023)	$	(14,221)	$	(8,388)	$	(1,201)
Net loss attributable to the period from January 1, 2014 to October 1, 2014		—		34,407
Net loss attributable to limited partners	$	(58,656)	$	(18,616)
Basic and diluted net loss from continuing operations per common unit	$	(1.19)	$	(0.52)
Basic and diluted net loss per common unit		(1.60)		(0.51)
Basic and diluted net loss from continuing operations per subordinated unit		(1.20)		(0.52)
Basic and diluted net loss per subordinated unit		(1.61)		(0.51)
Distributions declared per common and subordinated unit		1.279		—
Statement of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	46,041	$	30,157	$	13,882	$	(6,990)	$	(5,895)
Investing activities		(79,077)		(46,153)		(27,735)		(292,334)		(26,860)
Financing activities		31,698		16,087		6,988		304,991		34,825
Other Financial Data(2):
Adjusted gross margin	$	150,291	$	133,832	$	112,954	$	51,326	$	18,108
Adjusted EBITDA		46,865		31,651		34,284		14,560		2,825
Balance Sheet Data:
Cash and cash equivalents	$	1,987	$	3,325	$	3,234	$	10,099	$	4,432
Property, plant and equipment, net		291,454		251,690		227,068		181,142		27,720
Total assets		735,259		813,173		843,402		562,124		65,931
Total long-term debt (including current maturities)		163,194		84,508		184,846		167,739		16,948
Total partners’ capital		504,920		600,680		533,393		314,153		41,466
Operating Data(3):
Crude oil pipeline throughput (Bbl/d)		28,246		20,868		13,738		—		—
Crude oil sales (Bbl/d)		40,255		15,612		5,107		7,516		—
Refined products terminals throughput (Bbl/d)		62,075		63,859		69,071		57,143		—
NGL and refined product sales (Mgal/d)		211		200		181		129		61

(1) In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(2) 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.”

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(3) Represents the average daily throughput volume and the average daily sales volume in our crude oil pipelines and storage 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.

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. In the fourth quarter of 2015, we reorganized our business segments to match the change in our internal organization and management structure.  The segment changes reflect the focus of our chief operating decision maker (“CODM”) and how performance of operations is evaluated and resources are allocated. Therefore, the results of our formerly reported crude oil supply and logistics segment have been combined into our crude oil pipelines and storage segment.  As a result of the reorganization, our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) 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. Our primary business strategy is 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

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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 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.

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 with an initial term that expires in August 2017. 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, 2015, 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, 2015, the weather in Texas, Oklahoma, New Mexico, Arizona, Arkansas, Kansas and Missouri, the seven states in which our NGL sales business operates, was 5% 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.

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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.

In our crude oil pipelines and storage segment, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using financial swaps. In our cylinder-exchange business, we sell approximately half of our volumes pursuant to contracts of generally two to three years in duration, which allow us to re-negotiate prices at the time of contract renewal, and we sell the remaining volumes on demand or under month-to-month contracts and generally adjust prices on these contracts on an annual basis. We hedge a majority of the forecasted volumes under our fixed-price 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.

Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $61.36 per barrel to a low of $34.55 per barrel from January 1, 2015 through December 31, 2015 and have declined further in early 2016. Fluctuations in energy prices, like the recent declines in commodity prices of crude oil, can also greatly affect the development of new crude oil reserves. Further declines in commodity prices of crude oil could have a negative impact on exploration, development and production activity, and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets. We are unable to predict future potential movements in the market price for crude oil and, thus, cannot predict the ultimate impact of commodity prices on our operations. If commodity prices continue to trend lower as they did in the latter part of 2014 and the year ended December 31, 2015, this could lead to reduced profitability and may result in future potential impairments of long-lived assets, goodwill or intangible assets. We performed our annual impairment assessment of goodwill in the fourth quarter of 2015, which resulted in an impairment charge of $29.9 million. Due to the market conditions discussed above, there is an increased likelihood of incurring additional future goodwill impairments, which may be material.

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.

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

· 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 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).

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Adjusted EBITDA and adjusted gross margin are supplemental, non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

· 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.

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

	Year Ended December 31,
	2015		2014		2013		2012		2011
	(in thousands)
Reconciliation of Adjusted EBITDA to net loss
Net loss	$	(58,656)	$	(53,023)	$	(14,221)	$	(8,388)	$	(1,201)
Depreciation and amortization		46,852		40,230		30,987		12,941		2,841
Goodwill impairment		29,896		—		—		—		—
Interest expense		5,375		8,981		8,245		3,249		633
Loss on extinguishment of debt		—		1,634		—		497		95
Income tax expense		754		300		208		222		35
Loss on disposal of assets, net		909		1,137		1,492		1,142		68
Unit-based compensation		1,217		1,658		790		2,485		—
Total (gain) loss on commodity derivatives		3,057		13,762		(902)		(640)		—
Net cash payments for commodity derivatives settled during the period		(14,821)		(1,071)		(209)		(946)		—
Early settlement of commodity derivatives (1)		8,745		—		—		—		—
Corporate overhead support from general partner (2)		5,500		—		—		—		—
Transaction costs and other		1,877		3,766		1,286		1,492		354
Discontinued operations (3)		16,160		14,277		6,608		2,506		—
Adjusted EBITDA	$	46,865	$	31,651	$	34,284	$	14,560	$	2,825

(1) Due to its non-recurring nature, we excluded this transaction in calculating Adjusted EBITDA.

(2) Represents expenses incurred by us that were absorbed by our general partner and not passed through to us.

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(3) In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

	Year Ended December 31,
	2015		2014		2013		2012		2011
	(in thousands)
Reconciliation of adjusted gross margin to operating loss
Adjusted gross margin
Crude oil pipelines and storage	$	35,500	$	36,788	$	19,249	$	3,465	$	—
Refined products terminals and storage		14,578		16,834		19,328		1,732		—
NGL distribution and sales		100,213		80,210		74,377		46,129		18,108
Total Adjusted gross margin		150,291		133,832		112,954		51,326		18,108
Operating expenses		(69,377)		(65,584)		(57,728)		(26,292)		(9,584)
General and administrative		(45,383)		(46,362)		(44,488)		(20,785)		(6,053)
Depreciation and amortization		(46,852)		(40,230)		(30,987)		(12,941)		(2,841)
Goodwill impairment		(29,896)		—		—		—		—
Loss on disposal of assets, net		(909)		(1,137)		(1,492)		(1,142)		(68)
Total gain (loss) from commodity derivative contracts		(3,057)		(13,762)		902		640		—
Net cash payments for commodity derivatives settled during the period		14,821		1,071		209		947		—
Early settlement of commodity derivatives (1)		(8,745)		—		—		—		—
Other non-cash items		(201)		(669)		—		—		—
Operating loss	$	(39,308)	$	(32,841)	$	(20,630)	$	(8,247)	$	(438)

(1) Due to its non-recurring nature, we excluded this transaction in calculating adjusted gross margin.

Recent Developments

Disposition of Mid-Continent Crude Oil Supply and Logistics Assets

On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”), in connection with JP Development’s sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9.7 million; which included certain adjustments related to inventory and other working capital items. We continue to retain our crude oil storage operations in the Mid-Continent area of Oklahoma.

Current Year Highlights

Disposition of Crude Oil Supply and Logistics Assets

On September 30, 2015, we entered into an asset purchase agreement pursuant to which we sold certain crude oil supply and logistics assets for a sales price of $1.9 million. We closed the transaction on November 2, 2015 and recognized a gain on disposal of approximately $1.0 million.

Acquisition of Southern Propane Inc.

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

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Expansion of Silver Dollar Pipeline System

In February 2015, we signed a 10-year fee based gathering agreement with Discovery Natural Resources LLC (“Discovery”) to construct and operate an extension of our Silver Dollar Pipeline crude oil gathering system into the core of the Midland Basin. The agreement with Discovery is supported by a dedication of approximately 53,000 acres in Reagan, Glasscock, Sterling and Irion Counties. In addition to pipeline gathering, we also provide crude oil trucking, marketing and related services for Discovery. The gathering system extension consists of approximately 51 miles of pipeline, extending from southern Reagan County north into Glasscock County across the Midland Basin. In September 2015, we completed Phase I of the project, which included the construction and commissioning of 32 miles of pipeline and associated truck and measurement facilities. Phase II of the construction was completed in January 2016.  

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

In April 2015, we announced that we have executed an interconnection agreement with an affiliate of Magellan Midstream Partners, L.P. (“Magellan”) to connect our Silver Dollar Pipeline System to Magellan’s Longhorn pipeline at the Barnhart Terminal in Crockett County, Texas. The interconnection provides producers with a third takeaway option from the Silver Dollar Pipeline System and direct access from the core of the Midland Basin to end markets in Houston. The connection was completed and began service in September 2015. As part of the Magellan project, we also added 30,000 barrels of crude oil storage which further increased the total crude oil storage capacity on the Silver Dollar Pipeline to 140,000 barrels.

Factors Affecting the Comparability of Our Financial Results

Our historical results of operations may not be comparable due to our acquisition activity. Our acquisition activity and the resulting changes to our business have significantly affected our operations over the last four years. The acquisitions of our initial crude oil supply and logistics and our crude oil pipelines and storage operations, including our fleet of crude oil transportation trucks and our crude oil storage facility in Cushing, Oklahoma and our refined products terminals, all in the second half of 2012, transformed the magnitude and scope of our business and provided the initial assets and operations for our crude oil pipelines and storage segment and our refined products terminals and storage segment. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. Please read “Item 1. Business—Our Acquisition History” for greater detail about our acquisition history.

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Results of Operations

The following historical consolidated statements of operations data for the years ended December 31, 2015, 2014 and 2013 has been derived from our audited historical consolidated financial statements.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
TOTAL REVENUES	$	680,585	$	726,154	$	390,869
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		527,476		605,682		276,804
Operating expense		69,377		65,584		57,728
General and administrative		45,383		46,362		44,488
Depreciation and amortization		46,852		40,230		30,987
Goodwill impairment		29,896		—		—
Loss on disposal of assets, net		909		1,137		1,492
OPERATING LOSS		(39,308)		(32,841)		(20,630)
OTHER INCOME (EXPENSE)
Interest expense		(5,375)		(8,981)		(8,245)
Loss on extinguishment of debt		—		(1,634)		—
Other income, net		1,732		8		887
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(42,951)		(43,448)		(27,988)
Income tax expense		(754)		(300)		(208)
LOSS FROM CONTINUING OPERATIONS		(43,705)		(43,748)		(28,196)
DISCONTINUED OPERATIONS (1)
Net income (loss) from discontinued operations, including loss on disposal of $7,288 in 2014		(14,951)		(9,275)		13,975
NET LOSS	$	(58,656)	$	(53,023)	$	(14,221)

(1) In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Consolidated Results

	Year Ended December 31,
	2015		2014		Variance
		(in thousands)
Segment Adjusted EBITDA
Crude oil pipelines and storage (1)	$	23,119	$	25,339	$	(2,220)
Refined products terminals and storage (1)		10,867		10,723		144
NGL distribution and sales (1)		30,896		15,511		15,385
Discontinued operations (2)		1,209		5,002		(3,793)
Corporate and other		(19,226)		(24,924)		5,698
Total Adjusted EBITDA		46,865		31,651		15,214
Depreciation and amortization		(46,852)		(40,230)		(6,622)
Goodwill impairment		(29,896)		—		(29,896)
Interest expense		(5,375)		(8,981)		3,606
Loss on extinguishment of debt		—		(1,634)		1,634
Income tax expense		(754)		(300)		(454)
Loss on disposal of assets, net		(909)		(1,137)		228
Unit-based compensation		(1,217)		(1,658)		441
Total loss on commodity derivatives		(3,057)		(13,762)		10,705
Net cash payments for commodity derivatives settled during the period		14,821		1,071		13,750
Early settlement of commodity derivatives		(8,745)		—		(8,745)
Corporate overhead support from general partner		(5,500)		—		(5,500)
Transaction costs and other		(1,877)		(3,766)		1,889
Discontinued operations (2)		(16,160)		(14,277)		(1,883)
Net loss	$	(58,656)	$	(53,023)	$	(5,633)

(1) See further analysis of the Adjusted EBITDA of each reportable segment below.

(2) In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

Discontinued operations Adjusted EBITDA. Adjusted EBITDA related to discontinued operations included previously in our crude oil pipelines and storage segment decreased to $1.2 million for the year ended December 31, 2015 from $5.0 million for the year ended December 31, 2014. The decrease was primarily due to a decrease in crude oil sales margin in our operations in the Midcontinent region of Oklahoma and Kansas. We completed the sale of our crude oil logistics operations in the Midcontinent region in February 2016. In addition, we also completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming in June 2014, which contributed to the overall decrease for the year ended December 31, 2015 compared to the year ended December 31, 2014.

Corporate and other Adjusted EBITDA.  Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses decreased to $19.2 million for the year ended December 31, 2015 from $24.9 million for the year ended December 31, 2014. The decrease was primarily due to $5.5 million of expenses incurred by us during the year ended December 31, 2015, that were absorbed by our general partner and not passed through to us. An additional decrease of $3.2 million in professional and consulting fees was related to expenses associated with the IPO in the year ended December 31, 2014. These decreases were partially offset by increases of $1.9 million in employee expenses, $0.5 million in contract labor and $0.5 million in insurance expenses related to an increase in corporate personnel to support our business in the year ended December 31, 2015 compared to the year ended December 31, 2014.

Depreciation and amortization expense.  Depreciation and amortization expense for the year ended December 31, 2015 increased to $46.9 million from $40.2 million for the year ended December 31, 2014. The increase

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was primarily due to the expansions of our Silver Dollar Pipeline System in the fourth quarter of 2014 and throughout 2015. Our average depreciable asset base increased from $258.2 million during the year ended December 31, 2014 to $324.6 million during the year ended December 31, 2015.

Goodwill impairment. For the year ended December 31, 2015, we recognized goodwill impairment charges of $23.6 million and $6.3 millionin our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volumes in those reporting units.

Interest expense. Interest expense for the year ended December 31, 2015 decreased to $5.4 million from $9.0 million for the year ended December 31, 2014. The decrease was primarily due to the repayment of a substantial portion of our revolving credit facility utilizing a portion of the proceeds from our initial public offering completed on October 7, 2014, as well as a decrease in the average interest rate. Our average borrowings decreased from $177.9 million for the year ended December 31, 2014 to $141.6 million for the year ended December 31, 2015. Our average interest rate decreased from 5.1% for the year ended December 31, 2014 to 3.8% for the year ended December 31, 2015.

Loss on extinguishment of debt. Loss on extinguishment of debt of $1.6 million for the year ended December 31, 2014 relates to the write off of deferred financing costs associated with extinguishment of our 2011 revolving credit facility in February 2014.

Unit-based compensation.  Unit-based compensation for the year ended December 31, 2015 decreased to $1.2 million from $1.7 million for the year ended December 31, 2014. The higher expense in 2014 was primarily due to the accelerated vesting of certain awards in connection with our IPO in October 2014.

Total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period.The changes in both total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period are due to the more favorable position of our propane hedges during the year ended December 31, 2015 compared to the year ended December 31, 2014.

Early settlement of commodity derivatives. In August 2015, we paid approximately $8.7 million to settle all of our outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. Due to the non-recurring nature, we have excluded the $8.7 million early settlement of commodity derivatives in calculating Adjusted EBITDA.

Corporate overhead support from general partner. Corporate overhead support from general partner of $5.5 million represents expenses incurred by us during the year ended December 31, 2015, that were absorbed by our general partner and not passed through to us.

Transaction costs and other non-cash items. Transaction costs and other non-cash items decreased to $1.9 million for the year ended December 31, 2015 from $3.8 million for the year ended December 31, 2014.The decrease was primarily due to a decrease in non-cash employee expenses of $2.8 million related to changes in our management structure and personnel in the year ended December 31, 2015. An additional decrease of $1.9 million is related to changes in contingent consideration liabilities due to the post-acquisition performance of a portion of our assets. These decreases were partially offset by $1.4 million of expenses related to changes in our management structure and personnel in the year ended December 31, 2015 and an increase in transaction costs of $1.4 million.

Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense, impairment charges and loss on disposal of assets related to the discontinued operations previously owned by our crude oil pipelines and storage segment. Such expenses increased to $16.2 million for the year ended December 31, 2015 from $14.3 million for the year ended December 31, 2014. The increase was primarily due to an impairment charge of $12.9 million related to fixed assets, intangible assets and goodwill associated with the disposal of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas in 2015. This increase was partially offset by decreases in the loss on the disposal of assets of $9.1 million, non-cash depreciation and amortization expense

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of $1.4 million and non-cash inventory costing adjustments of $0.4 million in the year ended December 31, 2015 compared to the year ended December 31, 2014.

Segment Operating Results

Crude Oil Pipelines and Storage

	Year Ended December 31,
	2015		2014		Variance
	(in thousands, unless otherwise noted)
Volumes:
Crude oil pipeline throughput (Bbls/d) (1)		28,246		20,868		7,378
Crude oil sales (Bbls/d) (2)		40,255		15,612		24,643
Revenues:
Crude oil sales	$	456,349	$	470,336	$	(13,987)
Gathering, transportation and storage fees		21,820		24,013		(2,193)
Other revenues		2,358		1,622		736
Total Revenues		480,527		495,971		(15,444)
Cost of sales, excluding depreciation and amortization (3)		(445,027)		(459,183)		14,156
Adjusted gross margin		35,500		36,788		(1,288)
Operating expenses (3)		(9,238)		(7,928)		(1,310)
General and administrative (3)		(3,143)		(3,548)		405
Other income, net		—		27		(27)
Segment Adjusted EBITDA	$	23,119	$	25,339	$	(2,220)

(1) Represents the average daily throughput volume in our crude oil pipelines and storage segment. The volumes in our crude oil storage facility are excluded because they have no effect on operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.

(2) Represents the average daily sales volume in our crude oil pipelines and storage segment.

(3) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Volumes. Crude oil pipeline throughput volumes increased to 28,246 barrels per day for the year ended December 31, 2015 from 20,868 barrels per day for the year ended December 31, 2014. Crude oil sales volumes increased to 40,255 barrels per day for the year ended December 31, 2015 from 15,612 barrels per day for the year ended December 31, 2014. The increases were due to the expansions of the Silver Dollar Pipeline System in the third quarter of 2014 and throughout 2015.

Adjusted gross margin.Adjusted gross margin decreased to $35.5 million for the year ended December 31, 2015 from $36.8 million for the year ended December 31, 2014. The major components of this decrease were as follows:

· a $10.1 million decrease in crude oil sales margin primarily due to the impact of the current lower-priced crude oil market on margin per barrel and the lack of any market dislocation opportunities for the year ended December 31, 2015 compared to the year ended December 31, 2014.; partially offset by

· a $4.7 million increase in crude oil sales volumes and a $3.6 million increase in crude oil throughput volume on our Silver Dollar Pipeline System, as explained above.; and

· a $0.5 million increase in storage fees from a service outage that occurred to make repairs to a portion of our storage tanks in December 2014.

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Operating expenses.Operating expenses increased to $9.2 million for the year ended December 31, 2015 from $7.9 million for the year ended December 31, 2014. The increase was primarily due toincreases in insurance premiums ($0.8 million), property tax expenses ($0.2 million) and repairs and maintenance expenses ($0.2 million) in the year ended December 31, 2015.

Refined Products Terminals and Storage

	Year Ended December 31,
	2015		2014		Variance
	(in thousands, unless otherwise noted)
Volumes:
Terminal and storage throughput (Bbls/d) (1)		62,075		63,859		(1,784)
Revenues:
Refined products sales	$	10,394	$	11,521	$	(1,127)
Refined products terminals and storage fees		12,833		11,766		1,067
Total Revenues		23,227		23,287		(60)
Cost of sales, excluding depreciation and amortization (2)		(8,649)		(6,453)		(2,196)
Adjusted gross margin		14,578		16,834		(2,256)
Operating expenses (2)		(2,980)		(4,602)		1,622
General and administrative (2)		(737)		(1,518)		781
Other income		6		9		(3)
Segment Adjusted EBITDA	$	10,867	$	10,723	$	144

(1) Represents the average daily throughput volume in our refined products terminals and storage segment.

(2) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Revenues. Revenues decreased to $23.2 million for the year ended December 31, 2015 from $23.3 million for the year ended December 31, 2014. The decrease was primarily due to a decrease in refined product sales revenue of $1.1 million from a decrease in commodities prices ($4.1 million) in the year ended December 31, 2015 compared to the year ended December 31, 2014, partially offset by an increase in refined product sales volumes ($3.0 million) due to the addition of butane blending capabilities at our North Little Rock Terminal in the second quarter of 2015. The decrease in refined products sales revenue was partially offset by an increase in terminal throughput and additive fees of $0.6 million related to changes in our terminaling agreements in the year ended December 31, 2015 and an increase in storage fees of $0.3 million.

Cost of sales, excluding depreciation and amortization.Cost of sales, excluding depreciation and amortization increased to $8.6 million for the year ended December 31, 2015 from $6.5 million for the year ended December 31, 2014.  The increase was primarily due to an increase in refined products sales volumes.

Operating expenses.Operating expenses decreased to $3.0 million for the year ended December 31, 2015 from $4.6 million for the year ended December 31, 2014.  The decrease was primarily due to the recording of a non-recurring charge of $2.3 million at our North Little Rock, Arkansas terminal in the year ended December 31, 2014, related to the settlement of under-delivered product volumes with our North Little Rock terminal customers.

General and administrative.General and administrative decreased to $0.7 million for the year ended December 31, 2015 from $1.5 million for the year ended December 31, 2014. The decrease was primarily due to changes in our management structure and personnel in the year ended December 31, 2015 compared to the year ended December 31, 2014.

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NGL Distribution and Sales

	Year Ended December 31,
	2015		2014		Variance
	(in thousands, unless otherwise noted)
Volumes:
NGL and refined product sales (Mgal/d) (1)		211		200		11
Revenues:
Gathering, transportation and storage fees	$	5,960	$	6,688	$	(728)
NGL and refined product sales		159,616		188,701		(29,085)
Other revenues		11,255		11,507		(252)
Total Revenues		176,831		206,896		(30,065)
Cost of sales, excluding depreciation and amortization (2)		(76,618)		(126,686)		50,068
Adjusted gross margin		100,213		80,210		20,003
Operating expenses (2)		(57,200)		(52,109)		(5,091)
General and administrative (2)		(12,373)		(13,092)		719
Other income, net		256		502		(246)
Segment Adjusted EBITDA	$	30,896	$	15,511	$	15,385

(1) Represents the average daily sales volume in our NGL distribution and sales segment.

(2) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Adjusted gross margin. Adjusted gross margin increased to $100.2 million for the year ended December 31, 2015 from $80.2 million for the year ended December 31, 2014.  The increase was primarily due to an increase in the average NGL and refined product sales margin ($14.6 million) combined with an increase in NGL and refined products sales volume ($5.5 million). The average sales margin of NGL and refined products increased due to more favorable market conditions in the year ended December 31, 2015 compared to the year ended December 31, 2014.  Sales volumes increased as a result of organic growth in our customer base and the acquisition of Southern Propane in May 2015.

Operating expenses.Operating expenses increased to $57.2 million for the year ended December 31, 2015 from $52.1 million for the year ended December 31, 2014. The increase was primarily due to increases in employee costs of $4.0 million, distribution expenses of $0.6 million and insurance premiums of $0.5 million related to the increased sales volumes.

General and administrative.General and administrative decreased to $12.4 million for the year ended December 31, 2015 from $13.1 million for the year ended December 31, 2014.  The decrease was primarily due to changes in our management structure and personnel in the year ended December 31, 2015 compared to the year ended December 31, 2014.

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Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Consolidated Results

	Year ended December 31,
	2014		2013		Variance
	(in thousands)
Segment Adjusted EBITDA
Crude oil pipelines and storage (1)	$	25,339	$	9,479	$	15,860
Refined products terminals and storage (1)		10,723		16,100		(5,377)
NGL distribution and sales (1)		15,511		15,518		(7)
Discontinued operations (2)		5,002		20,583		(15,581)
Corporate and other		(24,924)		(27,396)		2,472
Total Adjusted EBITDA		31,651		34,284		(2,633)
Depreciation and amortization		(40,230)		(30,987)		(9,243)
Interest expense		(8,981)		(8,245)		(736)
Loss on extinguishment of debt		(1,634)		—		(1,634)
Income tax expense		(300)		(208)		(92)
Loss on disposal of assets, net		(1,137)		(1,492)		355
Unit-based compensation		(1,658)		(790)		(868)
Total gain (loss) on commodity derivatives		(13,762)		902		(14,664)
Net cash payments for commodity derivatives settled during the period		1,071		209		862
Transaction costs and other		(3,766)		(1,286)		(2,480)
Discontinued operations (2)		(14,277)		(6,608)		(7,669)
Net loss	$	(53,023)	$	(14,221)	$	(38,802)

(1) See further analysis of the Adjusted EBITDA of each reportable segment below.

(2) In February 2016, we completed the sale of our crude oil supply and logistics operations in the Midcontinent region of Oklahoma and Kansas. In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

Discontinued operations Adjusted EBITDA. Adjusted EBITDA related to the discontinued operations included previously in our crude oil pipelines and storage segment decreased to $5.0 million for the year ended December 31, 2014 from $20.6 million for the year ended December 31, 2013. The decrease was primarily due to decreases in crude oil sales margin ($12.9 million) and crude oil sales volumes ($4.0 million) in our operations in the Midcontinent region of Oklahoma and Kansas. The lack of existing pipeline takeaway capacity and associated logistical challenges created market conditions that provided us with more opportunities to capture above-baseline margins and volumes in 2013 compared to 2014. Due to increased competition, the impact of the current lower-priced crude oil market on margin per barrel and the lack of any market dislocation opportunities in the year ended December 31, 2015, we completed the sale of our crude oil logistics operations in the Midcontinent region in February 2016. In addition, we also completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming in June 2014, which contributed to the overall decrease for the year ended December 31, 2014 compared to the year ended December 31, 2013.

Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses decreased to $24.9 million for the year ended December 31, 2014 from $27.4 million for the year ended December 31, 2013. The decrease was primarily due to a decrease in professional fees of $5.5 million related to higher audit, consulting and legal expenses incurred in 2013 as a result of our IPO process. This decrease was partially offset by $3.4 million of increased payroll and benefits expenses related to the addition of corporate office personnel to support the growth of our business.

Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2014 increased to $40.2 million from $31.0 million for the year ended December 31, 2013. The increase

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was primarily due to four acquisitions completed during or after July 2013. These acquisitions accounted for at least seven more months of depreciation and amortization activity in 2014, which was not included in our 2013 financial results. Our property, plant and equipment base increased from $232.2 million as of December 31, 2013 to $258.2 million as of December 31, 2014.

Interest expense. Interest expense for the year ended December 31, 2014 increased to $9.0 million from $8.2 million for the year ended December 31, 2013. The increase was primarily due to an increase in average borrowings from $172.3 million for the year ended December 31, 2013 to $177.9 million for the year ended December 31, 2014.

Loss on extinguishment of debt. Loss on extinguishment of debt of $1.6 million for the year ended December 31, 2014 relates to the write off of deferred financing costs associated with extinguishment of our 2011 revolving credit facility in February 2014.

Unit-based compensation.  Unit-based compensation for the year ended December 31, 2014 increased to $1.7 million from $0.8 million for the year ended December 31, 2013. The increase was primarily due to the accelerated vesting of certain awards in 2014, in connection with our IPO.

Total gain (loss) on commodity derivatives and net cash payments for commodity derivatives settled during the period.The changes in both total gain (loss) on commodity derivatives and net cash payments for commodity derivatives settled during the period are due to the less favorable position of our propane hedges during the year ended December 31, 2014 compared to the year ended December 31, 2013.

Transaction costs and other non-cash items. Transaction costs and other non-cash items increased for the year ended December 31, 2014 to $3.8 million from $1.3 million for the year ended December 31, 2013 primarily due to an increase in non-cash personnel expenses of $2.4 million related to an increase in employee headcount to support the growth of our business.

Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense and loss on disposal of assets related to the discontinued operations previously owned by our crude oil pipelines and storage segment. Such expenses increased to $14.3 million for the year ended December 31, 2014 from $6.6 million for the year ended December 31, 2013. The increase was primarily due to the loss on the disposal of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming of $7.3 million in the year ended December 31, 2014.

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Segment Operating Results

Crude Oil Pipelines and Storage

	Year ended December 31,
	2014		2013		Variance
	(in thousands, unless otherwise noted)
Volumes:
Crude oil pipeline throughput (Bbls/d) (1)		20,868		13,738		7,130
Crude oil sales (Bbls/d) (2)		15,612		5,107		10,505
Revenues:
Crude oil sales	$	470,336	$	164,356	$	305,980
Gathering, transportation and storage fees		24,013		22,329		1,684
Other revenues		1,622		308		1,314
Total Revenues		495,971		186,993		308,978
Cost of sales, excluding depreciation and amortization (3)		(459,183)		(167,744)		(291,439)
Adjusted gross margin		36,788		19,249		17,539
Operating expenses (3)		(7,928)		(7,405)		(523)
General and administrative (3)		(3,548)		(2,365)		(1,183)
Other income, net		27		—		27
Segment Adjusted EBITDA	$	25,339	$	9,479	$	15,860

(1) Represents the average daily throughput volume in our crude oil pipelines and storage segment. The volumes in our crude oil storage facility are excluded because they have no effect on operations as we receive a set fee per month that does not fluctuate with the volume of crude oil stored.

(2) Represents the average daily sales volume in our crude oil pipelines and storage segment.

(3) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Volumes. Crude oil sales volumes increased to 15,612 barrels per day for the year ended December 31, 2014 from 5,107 barrels per day for the year ended December 31, 2013. Crude oil pipeline throughput increased to 20,868 barrels per day for the year ended December 31, 2014 from 13,738 barrels per day for the year ended December 31, 2013. The increases were primarily due to the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System.

Adjusted gross margin.  Adjusted gross margin increased to $36.8 million for the year ended December 31, 2014 from $19.3 million for the year ended December 31, 2013. The major components of this increase were as follows:

· an $8.6 million increase as a result of the acquisition of Wildcat Permian in October 2013, which owns the Silver Dollar Pipeline System; and

· an $8.4 million increase in crude oil sales volume, as explained above, combined with a $1.3 million increase in crude oil sales margin; partially offset by

· a $0.7 million decrease in storage fees from a service outage that occurred to make repairs to a portion of our storage tanks in December 2014.

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Operating expenses.  Operating expenses increased to $7.9 million for the year ended December 31, 2014 from $7.4 million for the year ended December 31, 2013. The increase was primarily due to the acquisition of Wildcat Permian in October 2013.

General and administrative.  General and administrative expenses increased to $3.5 million for the year ended December 31, 2014 from $2.4 million for the year ended December 31, 2013. The major components of this increase were as follows:

· a $0.6 million increase in operating expenses primarily due to the acquisition of Wildcat Permian in October 2013;  and

· a $0.4 million increase in office expenses incurred to support the growing business.

Refined Products Terminals and Storage

	Year ended December 31,
	2014		2013		Variance
	(in thousands, unless otherwise noted)
Volumes:
Terminal and storage throughput (Bbls/d) (1)		63,859		69,071		(5,212)
Revenues:
Refined products sales	$	11,521	$	11,702	$	(181)
Refined products terminals and storage fees		11,766		12,309		(543)
Total Revenues		23,287		24,011		(724)
Cost of sales, excluding depreciation and amortization (2)		(6,453)		(4,683)		(1,770)
Adjusted gross margin		16,834		19,328		(2,494)
Operating expenses (2)		(4,602)		(2,464)		(2,138)
General and administrative (2)		(1,518)		(772)		(746)
Other income		9		8		1
Segment Adjusted EBITDA	$	10,723	$	16,100	$	(5,377)

(1) Represents the average daily throughput volume in our refined products terminals and storage segment.

(2) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Revenues. Revenues decreased to $23.3 million for the year ended December 31, 2014 from $24.0 million for the year ended December 31, 2013. The decrease was primarily due to a decrease in terminal and storage throughput volumes ($0.5 million) related to increased competition near our North Little Rock Terminal, combined with a decrease in refined product sales revenue ($0.2 million) due to the decrease in refined product commodities prices in late 2014.

Cost of sales, excluding depreciation and amortization.    Cost of sales, excluding depreciation and amortization increased to $6.5 million for the year ended December 31, 2014 from $4.7 million for the year ended December 31, 2013. The increase was primarily due to the addition of conventional blendstocks for oxygenate blending (“CBOB”) at our Caddo Mills terminal in late December 2013, which resulted in additional cost of sales for the year ended December 31, 2014 that were not included in the year ended December 31, 2013.

Operating expenses.    Operating expenses increased to $4.6 million for the year ended December 31, 2014 from $2.5 million for the year ended December 31, 2013. The increase was primarily due to the recording of a charge of $2.3 million at our North Little Rock, Arkansas terminal in the year ended December 31, 2014. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal under-delivered refined products to its customers and consequently, recognized excess gains on

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refined products generated during the terminal’s normal terminal and storage process. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and in the fourth quarter of 2014 we returned approximately 20,900 barrels to certain customers, which amounted to a value of $2.1 million. In addition, we had approximately 3,100 barrels that was due to our customers as of December 31, 2014, which amounts to an estimated value of $0.2 million. Accordingly, we recorded a $2.3 million charge to operating expenses in the consolidated statement of operations for the year ended December 31, 2014.

General and administrative.    General and administrative increased to $1.5 million for the year ended December 31, 2014 from $0.8 million for the year ended December 31, 2013. The increase was primarily due to an increase in employee salary and benefit expenses of $0.7 million related to the realignment of personnel to support our refined products terminals and storage business.

NGL Distribution and Sales

	Year ended December 31,
	2014		2013		Variance
	(in thousands, unless otherwise noted)
Volumes:
NGL and refined product sales (Mgal/d) (1)		200		181		19
Revenues:
Gathering, transportation and storage fees	$	6,688	$	1,614	$	5,074
NGL and refined product sales		188,701		166,880		21,821
Other revenues		11,507		11,371		136
Total Revenues		206,896		179,865		27,031
Cost of sales, excluding depreciation and amortization (2)		(126,686)		(105,488)		(21,198)
Adjusted gross margin		80,210		74,377		5,833
Operating expenses (2)		(52,109)		(47,307)		(4,802)
General and administrative (2)		(13,092)		(11,688)		(1,404)
Other income, net		502		136		366
Segment Adjusted EBITDA	$	15,511	$	15,518	$	(7)

(1) Represents the average daily sales volume in our NGL distribution and sales segment.

(2) Certain expenses have been excluded from cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses for the purpose of calculating segment Adjusted EBITDA.

Adjusted gross margin. Adjusted gross margin increased to $80.2 million for the year ended December 31, 2014 from $74.4 million for the year ended December 31, 2013. The major components of this increase were as follows:

· an increase in NGL and refined product sales volumes ($7.7 million) partially offset by a decrease in average propane sales margin ($3.8 million). Sales volumes increased as a result of an expansion in our wholesale customer base in 2014, as well as the acquisition of BMH Propane, LLC (“BMH”) in July 2013; and

· the acquisition of Highway Pipeline, Inc. (“HPI”) in October 2013, which generated $2.5 million of adjusted gross margin from the gathering and transportation of NGLs in the year ended December 31, 2014, compared to $0.6 million in the year ended December 31, 2013.

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Operating expenses. Operating expenses increased to $52.1 million for the year ended December 31, 2014 from $47.3 million for the year ended December 31, 2013. The major components of this increase were as follows:

· the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $2.8 million of operating expenses in the year ended December 31, 2014, compared to $0.8 million in the year ended December 31, 2013; and

· increases of $1.3 million in operating freight expenses, $0.8 million in repairs and maintenance and $0.6 million in operating salaries, as a result of the western expansion of our cylinder exchange business.

General and administrative. General and administrative increased to $13.1 million for the year ended December 31, 2014 from $11.7 million for the year ended December 31, 2013. The major components of this increase were as follows:

· the acquisitions of BMH in July 2013, and HPI in October 2013. These acquired businesses incurred $0.9 million of general and administrative expenses in the year ended December 31, 2014, compared to $0.3 million in the year ended December 31, 2013; and

· increase in employee costs of approximately $0.7 million, as a result of the increase in headcount to support our growing business.

Liquidity and Capital Resources

We principally require liquidity to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. We expect our sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and issuances of debt and equity.

We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our cash distribution requirements. We believe that future internal growth projects or potential acquisitions will be funded primarily through borrowings under our revolving credit facility or through issuances of debt and equity securities. However, future issuances of equity securities are subject to a recovery in the market price of our common units from current depressed levels.

Distributions

We intend to pay a minimum quarterly distribution of $0.3250 per unit per quarter, which equates to approximately $11.9 million per quarter, or $47.6 million per year, calculated based on the number of common and subordinated units outstanding as of February 22, 2016 and estimated unvested phantom units under our long-term incentive plan. We do not have a legal obligation to pay this distribution, except as provided in our partnership agreement. We currently estimate that our distributable cash flow in certain quarters of 2016 will be less than our anticipated distributions to unitholders during those periods. This shortfall is expected to be temporary and is expected to be funded with a combination of borrowings from our revolving credit facility and corporate overhead support from our general partner.

Revolving Credit Facility

Our revolving credit facility has a maturity date of February 12, 2019 and consists of a $275.0 million revolving line of credit, which includes a sub-limit of up to $100.0 million for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275.0 million to $425.0 million, subject to obtaining additional or increased lender commitments. Our revolving credit facility is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and for general partnership purposes, including distributions, not in contravention of law or the loan documents. Substantially all of our assets, but excluding equity in and assets of unrestricted subsidiaries and other customary exclusions, are pledged as

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collateral under our revolving credit facility. Our revolving credit facility contains customary covenants, including, among others, those that restrict our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on our assets.  Our revolving credit facility also requires compliance with certain financial covenants, which include the following:

· a consolidated interest coverage ratio of not less than 2.50;

· prior to our issuance of certain unsecured notes, (i) a consolidated net total leverage ratio of not more than 4.50 and (ii) from and after our issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 5.00;

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

· available liquidity, as defined in the credit agreement, of not less than $25.0 million.

Prior to February 23, 2016, our revolving credit facility contained a covenant requiring our consolidated working capital, as defined in the credit agreement, to be not less than $15.0 million. We were not in compliance with the consolidated working capital covenant as of December 31, 2015, which noncompliance was waived and which covenant was removed and the available liquidity covenant was added pursuant to Amendment No. 5.

As of February 22, 2016, we had $150.0 million of outstanding borrowings under our revolving credit facility and a remaining borrowing capacity of $97.0 million thereunder. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $28.0 million as of February 22, 2016.

Borrowings under our revolving credit facility bear interest at a rate per annum equal to, at our option, either (a) a Base Rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an Applicable Rate (Base Rate, LIBOR and Applicable Rate each as defined in our revolving credit facility). As of December 31, 2015, the Applicable Rate for Base Rate loans range from 0.75% to 2.00% and the Applicable Rate for LIBOR loans range from 1.75% to 3.00%, in each case based on our consolidated net total leverage ratio.

Cash Flow

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

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Operating activities	$	46,041	$	30,157	$	13,882
Investing activities		(79,077)		(46,153)		(27,735)
Financing activities		31,698		16,087		6,988

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Cash provided by operating activities. Cash provided by operating activities was $46.0 million for the year ended December 31, 2015 compared to $30.2 million for the year ended December 31, 2014. The $15.8 million increase was primarily attributable to a $15.2 million increase in total Adjusted EBITDA.

Cash used in investing activities. Cash used in investing activities was $79.1 million for the year ended December 31, 2015 compared to $46.2 million for the year ended December 31, 2014. The $32.9 million increase was primarily due to an increase in capital expenditures of $14.1 million in the year ended December 31, 2015 associated with our organic growth projects, $12.6 million related to the acquisition of Southern Propane in 2015 and a $7.4 million

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decrease in the proceeds from the sale of assets. These increases were partially offset by a $1.2 million change in restricted cash.

Cash provided by financing activities. Cash provided by financing activities was $31.7 million for the year ended December 31, 2015 compared to $16.1 million for the year ended December 31, 2014. For the year ended December 31, 2015, cash provided by financing activities included net borrowings under our revolving credit facility and other debt of $78.6 million, partially offset by distributions to unitholders of $47.0 million. For the year ended December 31, 2014, cash provided by financing activities included cash provided by the issuance of common and preferred units of $302.6 million, partially offset by net payments under our revolving credit facility and other debt of $100.4 million, distributions to unitholders of $92.0 million, $52.0 million used to purchase the Dropdown Assets and $42.4 million of cash used to redeem preferred units.

Cash flows from discontinued operations. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from these discontinued operations will have a significant impact to our future liquidity.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Cash provided by operating activities. Cash provided by operating activities was $30.2 million for the year ended December 31, 2014 compared to $13.9 million for the year ended December 31, 2013. The $16.3 million increase was primarily attributable to a $33.3 million decrease in cash used for crude oil inventory purchase year-over-year, as we lowered our crude oil inventory level in our crude oil pipelines and storage segment due to improved operational efficiency. The increase was partially offset by a $13.2 million decrease from the timing of collections and payments and a $2.6 million decrease in total Adjusted EBITDA.

Cash used in investing activities. Cash used in investing activities was $46.2 million for the year ended December 31, 2014 compared to $27.7 million for the year ended December 31, 2013. The $18.5 million increase was primarily due to an increase in capital expenditures of $30.1 million in the year ended December 31, 2014 associated with our organic growth projects, partially offset by a $11.2 million increase in proceeds from the sale of assets.

Cash provided by financing activities. Cash provided by financing activities was $16.1 million for the year ended December 31, 2014 compared to $7.0 million for the year ended December 31, 2013. The $9.1 million change was primarily due to a $259.5 million increase from the issuance of units. This amount is partially offset by a $115.4 million decrease in net borrowings under our revolving credit facility and term loans, a $74.5 million increase in distributions to unitholders and the $52.0 million of cash used for the JP Development Dropdown.

Cash flows from discontinued operations. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from these discontinued operations will have a significant impact to our future liquidity.

Capital Expenditures

Our capital expenditures were $83.6 million, $108.9 million and $27.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, which included capital expenditures for acquisitions of $12.6 million, $52.0 million and $1.0 million, respectively.

Our capital spending program is focused on expanding our pipeline and cylinder exchange businesses, maintaining our fleet and storage assets and maintaining and updating our information systems. Capital expenditure plans are generally evaluated based on return on investment and estimated incremental cash flow. In addition to annually recurring capital expenditures, potential acquisition opportunities are evaluated based on their anticipated return on invested capital, accretive impact to operating results and strategic fit.

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

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will increase our operating income or operating capacity over the long-term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, growth capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities.

Our capital expenditures were $83.6 million for the year ended December 31, 2015, which included capital expenditures for acquisitions of $12.6 million. For the year ended December 31, 2015, we spent $71.0 million on capital expenditures, excluding acquisitions, of which $5.3 million represents maintenance capital expenditures and $65.7 million represents growth capital expenditures. We have budgeted $5.0 million in maintenance capital expenditures for the year ending December 31, 2016. We expect growth capital expenditures for the year ending December 31, 2016 to range from $25.0 million to $35.0 million, with an estimated $15.0 million of these investments to be made on the continued development of our Silver Dollar Pipeline system. This estimated range of growth capital expenditures does not include any potential third party acquisitions that we will continue to evaluate throughout 2016.

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

Contractual Obligations

A summary of our contractual obligations as of December 31, 2015 is as follows:

	Less Than 1						More Than 5
	Year		1‑3 Years		3‑5 Years		Years		Total
	(in thousands)
Long-term debt obligations	$	454	$	740	$	162,000	$	—	$	163,194
Capital lease obligations(1)		153		156		53		11		373
Operating lease obligations(1)		5,116		8,107		3,101		4,877		21,201
Total	$	5,723	$	9,003	$	165,154	$	4,888	$	184,768

(1) Represents future minimum lease payments under non-cancelable operating and capital leases related to various buildings, land, storage facilities, transportation vehicles and office equipment. See Note 10 and Note 15 to our audited consolidated financial statements.

Off Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off balance sheet liabilities, except for operating lease commitments as disclosed in the contractual obligations table above.

Working Capital

Our working capital is the amount by which our current assets exceed our current liabilities and is a measure of our ability to pay our liabilities as they come due. Our working capital was $16.7 million, $26.3 million and $48.7 million as of December 31, 2015, 2014 and 2013, respectively.

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Our working capital requirements have been and will continue to be primarily driven by changes in accounts receivable and accounts payable, which generally fluctuate with changes in the market prices of commodities that we buy and sell in the ordinary course of our business. Other factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as our level of spending for maintenance and growth capital expenditures. A material adverse change in our operations or available financing under our revolving credit facility could impact our ability to fund our working capital requirements for liquidity and capital resources.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 2 to our consolidated financial statements. We prepare our consolidated financial statements in conformity with GAAP, and in the process of applying these principles, we must make judgments, assumptions and estimates based on the best available information at the time. To aid a reader’s understanding, management has identified our critical accounting policies. These policies are considered critical because they are both most important to the portrayal of our financial condition and results, and require our most difficult, subjective or complex judgments. Often they require judgments and estimation about matters which are inherently uncertain and involve measuring, at a specific point in time, events which are continuous in nature. Actual results may differ based on the accuracy of the information utilized and subsequent events, some over which we may have little or no control.

Revenue Recognition

We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller’s price to the buyer is fixed and determinable and collectability is reasonably assured. Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, are presented on a net basis within the consolidated statements of operations.

Crude oil pipelines and storage.  We generate revenue through crude oil sales and pipeline transportation and storage fees. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, we enter into sale and purchase contracts with counterparties that are the equivalent of pipeline transportation agreements. In such cases, we assess the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. We also generate revenue through crude oil sales. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty in which the buy and sell of inventory are in contemplation of each other. Revenue from such inventory exchange arrangements is recorded on a net basis. In addition, we also provide crude oil transportation services to third party customers.

Refined products terminals and storage.  We generate fee-based revenues with customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Such fee-based revenues are recognized when services are provided upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

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

Impairment of Long-Lived Assets

Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for

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possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary. For assets held for sale, we compare the fair value of the disposal group to its carrying value. Under the assets held for sale criteria, the order of impairment is based on (i) testing other assets, such as accounts receivable, inventory and indefinite-lived intangible assets, for impairment, (ii) testing goodwill for impairment and (iii) testing the long-lived asset group for impairment. In connection with the sale of our Mid-Continent Business, which was classified as held for sale at December 31, 2015, we recorded an impairment charge of $5.0 million during the year ended December 31, 2015 related to long-lived assets.

Goodwill

We apply Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill. In accordance with these standards, goodwill is not amortized but is tested for impairment at least annually, or more frequently whenever a triggering event or change in circumstances occurs at the reporting unit level. A reporting unit is the operating segment, or business one level below the operating segment if discrete financial information is prepared and regularly reviewed by segment management. We have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.

In 2015, we recognized impairment charges of $23.6 million and $6.3 million, related to the goodwill in our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volume in those reporting units.  We also recorded an additional goodwill impairment charge of $7.9 million triggered by the disposition of our Mid-Continent Business. The $7.9 million of goodwill was allocated to the Mid-Continent Business and the portion of the reporting unit that was retained by us. No provision for impairment of goodwill was recorded during 2014 or 2013.

During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the crude oil supply and logistics reporting unit, we allocated $2.0 million of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by us. The $2.0 million allocation contributed to the overall net loss from discontinued operations.

Risk Management Activities and Derivative Financial Instruments

We have established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The board of directors of our general partner is responsible for the overall management of these risks, including monitoring exposure limits. We do not enter into derivative instruments for any purpose other than management of commodity price and interest rate risks. We enter into commodity forward and swap contracts to hedge exposures to market fluctuations in crude oil and propane prices and interest rate swap contracts to hedge exposures to variable interest rate risk. These derivative contracts are reported in our consolidated balance sheets at fair value with changes in fair value recognized in cost of sales, excluding depreciation and amortization, and interest expense in our consolidated statements of operations. We estimate the fair value of our derivative contracts using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves. Changes in the methods used to determine the fair value of these contracts could have a material effect on our consolidated balance sheets and consolidated statements of operations. For further discussion of derivative contracts, see Note 13 to our audited consolidated financial statements included

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elsewhere in Form 10-K. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

Business Combinations

When a business is acquired, we allocate the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. ASC 805, Business Combinations, requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs incurred for the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt’s stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite.

When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting, whereby the assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

Equity-Based Compensation

ASC 718, Stock Compensation, requires all share-based payments to employees to be recognized in the financial statements, based on the fair value on the grant date, date of modification or end of the period, as applicable, and recognized in earnings over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as equity in the consolidated balance sheets. Equity-based compensation costs associated with the portion of awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Prior to our IPO in October 2014, we used to estimate the fair value of our common units by dividing the estimated total enterprise value by the number of outstanding units. Estimated total enterprise value was determined using the income approach of discounting the estimated future cash flow to its present value. We also estimated a 41% forfeiture rate in calculating the unit-based compensation expense.

Recent Accounting Pronouncements

In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 requires equity investments to be measured at fair value with changes in fair value recognized in net income; simplifies the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; requires separate presentation of financial assets and financial liabilities by measurement category and form of financial assets on the balance sheet or the accompanying notes to the financial statements and clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. This standard does not allow for early adoption except related to credit risk adjustment in other comprehensive income. The adoption of ASU 2016-01 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In November 2015 the FASB issued ASU 2015-17 Balance Sheet Classification of Deferred Taxes, which requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This ASU is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early application permitted and, upon adoption, may be applied either prospectively or retrospectively. We have early adopted, retrospectively, ASU 2015-17. The adoption of this ASU has no

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impact on the classification of our deferred taxes as they are already presented under the non-current classification for all periods presented.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). ASU 2015-16 changes how the acquirer recognizes adjustments to the provisional amounts of a business combination that are identified during the measurement period  from a retrospective application of all affected financial periods to be recorded in the reporting period in which the adjustment amounts are determined. Additionally, the Partnership needs to disclose, of the amounts recorded in current periods, what amounts would have been reported in previous periods if the adjustments had been recognized at the acquisition date.  ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015.  Early adoption of this ASU is permitted. The adoption of ASU 2015-16 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). ASU 2015-15 provides SEC Staff guidance to ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost as it relates to debt issuance cost associated with line-of-credit arrangements. The SEC staff recognized that ASU 2015-03 did not address presentation or subsequent measurement of debt issuances cost related to line-of-credit arrangements and noted that the SEC Staff wouldn’t object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings of the line-of credit arrangement.  We adopted ASU 2015-15 in the third quarter of 2015 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

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

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

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

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 provides amended guidance on the consolidation evaluation for reporting entities that are required to evaluate whether they should consolidate certain legal entities, including limited partnerships. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted.

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The adoption of ASU 2015-02 is not expected to have a material impact on our consolidated financial statements and related disclosures.

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES OF MARKET RISK.

Commodity price risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices. See “Note 12 — Derivative Instruments” included in our audited consolidated financial statements in Part IV, Item 15 of this report for additional information.

In our crude oil pipelines and storage segment, we purchase and take title to a portion of the crude oil that we sell, which exposes us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our refined products terminals and storage segment, we sell excess volumes of refined products and our gross margin is impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL distribution and sales business, we are generally able to pass through the cost of products through sales prices to our customers. To the extent we enter into fixed price product sales contracts in this business, we generally hedge our supply costs using fixed price forward contracts and swap contracts. In our cylinder exchange business, we sell approximately half of our volumes pursuant to contracts of generally one 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 majority of the forecasted volumes under our fixed-price contracts using financial swaps, and we may also use financial swaps to manage commodity price risk on our month-to-month contracts. At times we may also terminate or unwind hedges or a portion of hedges in order to meet cash flow objectives or when the expected future volumes do not support the level of hedges. In our NGL transportation business, we do not take title to the products we transport and therefore have no direct commodity price exposure.

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

	Maturity		Notional Volume		Fair Value Asset/(Liability)		Effect of Hypothetical 10% Change
					(in thousands)
Fixed Price Swaps:
Propane (Gallons)		Oct 2015 - Jul 2017		8,614,631	$	(431)	$	332
Crude Oil (Barrels)		Jan 2016		(93,000)		47		(348)

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

In August 2015, we paid approximately $8,745,000 to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

Interest rate risk.Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable interest rates. As of December 31, 2015, none of our outstanding debt is economically hedged. Based on our overall interest rate exposure to variable rate debt outstanding as of December 31, 2015, a 1% increase or decrease in interest rates would change interest expense by approximately $1.6 million.

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

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our audited consolidated financial statements are included in this Annual Report on Form 10-K and incorporated herein by reference. See the Index to Consolidated Financial Statements on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of December 31, 2015.  Based on this evaluation, our Chief Executive Officer and Chief

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Financial Officer concluded that as of December 31, 2015, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Remediation of Material Weaknesses

In previous annual and quarterly reports, we disclosed the following material weaknesses in our internal control over financial reporting:  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 (1) formal accounting policies and formal review controls; (2) 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 (3) 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.

As described in Item 4, “Controls and Procedures,” of our September 30, 2015 Form 10-Q, the material weakness related to business combinations was remediated in the quarter ended September 30, 2015.

As of December 31, 2015, we have remediated the remaining material weaknesses related to accounting personnel, policies and review controls, and information technology. The remediation of these material weaknesses included the implementation of the following:

Accounting Personnel

During 2013 and 2014, we hired multiple accounting professionals with adequate accounting and financial reporting experience in various roles in the accounting organization, and we hired internal audit professionals with experience in designing and testing internal control over financial reporting.  Key roles include: Chief Accounting Officer, Director of Corporate Accounting, Corporate Accounting Manager, Director of Financial Reporting, Manager of Financial Reporting, Director of Internal Audit and Manager of Internal Audit.  With the addition of these personnel, and others, we have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements.  There were no significant hires within accounting or internal audit for the quarter ended December 31, 2015.

Accounting Policies and Review Controls

We have implemented controls over GAAP and SEC reporting and disclosures.  Controls include: the performance and review of monthly account reconciliation; the implementation and review of a formal accounting closing checklist; review and approval of manual journal entries; the formation of a disclosure committee and the quarterly committee meeting to review our periodic SEC filings; the performance and review of the reconciliation of financial statements to the corresponding supporting documents.  There were no changes to our accounting policies and review controls for the quarter ended December 31, 2015. 

Information Technology

We implemented policies, procedures and controls with respect to the primary components of information technology general controls, including controls over the approval and review of access controls, system implementation and migration controls, and change management controls. There were no changes to the design of our information technology general controls for the quarter ended December 31, 2015.

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In the fourth quarter of 2015, we completed our remediation activities by testing the design and operating effectiveness of the internal controls over financial reporting implemented controls to address the remaining material weaknesses described above and found them to be effective. As a result, we have concluded that the material weaknesses related to these areas have been remediated as of December 31, 2015.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Companymanagementisresponsibleforestablishingandmaintainingadequateinternalcontroloverfinancial reporting(asisdefinedintheExchangeActRule 13a-15(f)).Ourinternalcontroloverfinancialreportingisdesignedto providereasonableassuranceregardingthereliabilityoffinancialreportingandthepreparationofourfinancial statementsforexternalpurposesinaccordancewithgenerallyacceptedaccountingprinciples.We usedthecriteria established inInternalControl-IntegratedFramework(2013)issuedbytheCommitteeofSponsoringOrganizationsofthe TreadwayCommission(''COSO")toevaluatetheeffectivenessofourinternalcontroloverfinancialreportingasofDecember31,2015.Basedonthatevaluation,ourmanagementconcludedthatourinternalcontroloverfinancialreporting waseffectiveasof December31,2015.

PricewaterhouseCoopersLLPourindependent registeredpublicaccountingfirm, auditedtheeffectivenessofourinternalcontroloverfinancialreportingasof December31,2015,asstatedintheirreportwhichappearsunderItem 15.

ITEM 9B. OTHER INFORMATION

Goodwill Impairment

On February 29, 2016, as part of our annual assessment of goodwill impairment conducted in connection with the preparation of our financial statements for the period ended December 31, 2015, we recorded impairment charges of $23.6 million and $6.3 million, related to the goodwill in our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volume in those reporting units. We also recorded an additional goodwill impairment charge of $7.9 million triggered by the disposition of our Mid-Continent Business. No provision for impairment of goodwill was recorded during 2014 or 2013.

The impairment charges described above are not expected to result in future capital expenditures. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Goodwill and Intangible Assets.”

Amendment to Credit Agreement

Our revolving credit facility contains covenants requiring compliance with certain financial covenants, including maintaining consolidated working capital (as defined in our credit agreement) of not less than $15.0 million.  On February 23, 2016, we entered into Amendment No. 5 to credit agreement by and among the Partnership, Bank of America, N.A., as Administrative Agent, and the lenders party thereto, pursuant to which, among other things, we eliminated the consolidated working capital covenant and added an available liquidity covenant.  We were not in compliance with the consolidated working capital covenant as of December 31, 2015, which noncompliance was waived pursuant to Amendment No. 5.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Management of JP Energy Partners LP

We are managed by the directors and executive officers of our general partner, JP Energy GP II LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Lonestar and members of our management directly own 95% of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors and cannot directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner has nine directors, including three independent directors. The members of our general partner, including Lonestar, will appoint all members to the board of directors of our general partner. Our board has determined that T. Porter Trimble, Norman J. Szydlowski and Josh L. Sherman are independent under the independence standards of the NYSE.

Neither we nor our subsidiaries will have any employees. Our general partner will have the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business will be employed by our general partner, but we sometimes refer to these individuals in this Form 10-K as our employees.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The board of directors of our general partner has an audit committee, a compensation committee and, as necessary, a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the committees of the board of directors has the composition and responsibilities described below.

Audit Committee

T. Porter Trimble, Norman J. Szydlowski and Josh L. Sherman serve as members of our audit committee. Our audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to our audit committee. Our general partner has adopted a written charter for our Audit Committee, which is available on our website at www.jpenergypartners.com.

Josh L. Sherman has been designated by the board as the audit committee’s financial expert meeting the requirements promulgated by the SEC and set forth in Item 407(d) of Regulation S-K based upon his education and employment experience as more fully detailed in Mr. Sherman’s biography set forth below. Mr. Sherman also acts as the Chairman of our audit committee.

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Compensation Committee

John F. Erhard, Norman J. Szydlowski and T. Porter Trimble serve as members of our compensation committee. The compensation committee will establish salaries, incentives and other forms of compensation for officers and other employees. The compensation committee also administers our incentive compensation and benefit plans. The NYSE does not require publicly traded partnerships, such as us, to have a compensation committee or, for publicly traded partnerships like us that have voluntarily elected to have a compensation committee, require that the members of the compensation committee be independent directors. Our general partner has adopted a written charter for our Compensation Committee, which is available on our website at www.jpenergypartners.com.

Conflicts Committee

At least two members of the board of directors of our general partner will serve on our conflicts committee each time it is formed to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. T. Porter Trimble, Norman J. Szydlowski and Josh L. Sherman have, in the past, served as the members of the conflicts committee. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than (i) common units and (ii) awards under our incentive compensation plan. Any matters approved by our conflicts committee will be presumed to have been approved in good faith, will be deemed to be approved by all of our partners and will not be a breach by our general partner of any duties it may owe us or our unitholders.

Corporate Governance

Our general partner has adopted a code of business conduct and ethics for all directors, officers, employees, and agents. If our general partner amends the code of business conduct and ethics or grants a waiver, including an implicit waiver, from the code of business conduct and ethics, we will disclose this information on our website. Our general partner has also adopted corporate governance guidelines that outline the important policies and practices regarding our corporate governance and provide that the Chairman of the Audit Committee shall preside over any executive sessions. Our corporate governance guidelines also outline how interested parties may communicate directly with the independent Board members. Each of the foregoing is available on our website at www.jpenergypartners.com in the “Corporate Governance” section.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10% unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.

Based solely upon a review of Forms 3, 4 and 5, and amendments thereto, we know of no director, officer, or beneficial owner of more than 10% of any class of our equity securities registered pursuant to Section 12 of the Exchange Act that failed to file timely any reports required to be furnished during 2015 pursuant to Section 16(a) of the Exchange Act, except that on April 30, 2015, Patrick J. Welch filed a Form 4 that was due on April 9, 2015 and on April 30, 2015, Jeremiah J. Ashcroft III filed a Form 4 that was due on April 16, 2015.

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Directors and Executive Officers of JP Energy GP II LLC

Directors are elected by the members of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of JP Energy GP II LLC.

Name	Age		Position with JP Energy GP II LLC
J. Patrick Barley	41		Chairman of the Board, President and Chief Executive Officer
Patrick J. Welch	48		Executive Vice President, Chief Financial Officer and Director
Jon E. Hanna	50		Executive Vice President—Crude Oil Pipelines and Storage
Shiming Chen	41		Senior Vice President and Chief Accounting Officer
Forgan McIntosh		37	Senior Vice President—Commercial and Corporate Development
Cory Willis		39	Senior Vice President—Terminals and Distribution
John F. Erhard	41		Director
Daniel R. Revers	54		Director
Evan M. Schwartz	33		Director
Greg Arnold	52		Director
T. Porter Trimble	55		Director
Norman J. Szydlowski	64		Director
Josh L. Sherman	40		Director

J. Patrick Barley. J. Patrick Barley has served as President, Chief Executive Officer and Chairman of the Board of directors of our general partner since May 2010. Mr. Barley brings over 16 years of experience managing early-stage investments. Prior to founding JP Energy Partners, Mr. Barley was the Founder, President and Chief Executive Officer of Lonestar Midstream Partners, LP (“Lonestar Midstream”), a midstream company focused on natural gas gathering and processing, from March 2005 to July 2008. Mr. Barley managed his private investments from the sale of Lonestar Midstream to Penn Virginia Resources Partners LP in July 2008 until he founded JP Energy Partners in May 2010. In 2004, Mr. Barley formed his own private investment firm, CB Capital, LLC, which served as the general partner of Lonestar Midstream. Prior to forming CB Capital, LLC, Mr. Barley was a partner at Greenfield Capital Management, LLC from 1999 to 2004. Mr. Barley earned a Bachelor of Science from Texas Tech University and a Master of Business Administration in Finance from Southern Methodist University.

Patrick J. Welch. Patrick J. Welch has served as the Executive Vice President and Chief Financial Officer of our general partner since April 2014 and served as Interim Chief Financial Officer of our general partner from November 2013 to April 2014. Mr. Welch was named to the board of directors of our general partner in October 2014. From August 2013 to April 2014, Mr. Welch served as a Managing Director at Opportune LLP, an independent consultancy focused exclusively on the energy industry. From March 2012 to August 2013, Mr. Welch served as an independent consultant, advising and assisting clients in all aspects of the CFO function in energy companies with a focus on IPO readiness. From June 2011 through March 2012, he served as Chief Financial Officer for RES Americas, a privately held renewable energy development and construction company with activities in the United States and Canada. Mr. Welch served as the Chief Financial Officer of Atlantic Power Corporation (NYSE: AT) from May 2006 through June 2011. Mr. Welch has an extensive background in the energy and independent power industries. Before joining Atlantic Power Corporation, from January 2004 to May 2006, Mr. Welch was Vice President and Controller of DCP Midstream and DCP Midstream Partners, LP (NYSE: DPM) in Denver, Colorado. Prior to that he held various positions at Dynegy Inc. (NYSE: DYN) in Houston, Texas, including Vice President and Controller for Dynegy Generation, and Assistant Corporate Controller. Prior to Dynegy, Mr. Welch was a Senior Audit Manager in the Energy, Utilities and Mining Practice of PricewaterhouseCoopers LLP, predominantly in Houston, Texas, where he served several major energy clients. Mr. Welch earned his Bachelor’s Degree from the University of Central Oklahoma and is a Certified Public Accountant.

Jon E. Hanna. Jon E. Hanna has served as Executive Vice President—Crude Oil Pipelines and Storage of our general partner since September 2015 and served as Executive Vice President—Commercial and Business Development from January 2014 to September 2015. Prior to joining JP Energy Partners, Mr. Hanna was Vice President—Business

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Development of Enable Midstream Partners, a natural gas gathering, processing, transportation and storage partnership, from August 2011 to December 2013. Prior to Enable, Mr. Hanna served as Vice President—Market Development for ONEOK Partners, a natural gas gathering, processing, storage and transportation partnership, from July 2007 to August 2011 and as Vice President—Business Development for ONEOK Hydrocarbon L.P., a NGL processing, storage and transportation partnership, from July 2005 to July 2007. Mr. Hanna held various other positions with ONEOK NGL Marketing, L.P. and ONEOK Energy Marketing from September 2000 to July 2005. Prior to joining ONEOK, Mr. Hanna held positions with Texaco Inc. relating to its NGL and natural gas businesses from November 1989 to September 2000. Mr. Hanna earned a Bachelor of Science in Business Administration from Drake University.

Shiming (Simon) Chen. Simon Chen has served as the Senior Vice President and Chief Accounting Officer of our general partner since November 2014. Mr. Chen served as Vice President, Chief Accounting Officer and Controller of our general partner from November 2014 to September 2015 and as Vice President and Controller of our general partner from February 2013 to November 2014. Prior to joining JP Energy Partners, Mr. Chen served as the Assistant Controller from October 2010 to February 2013, and Director of Financial Reporting from July 2009 to October 2010 for Regency Energy Partners LP, a midstream company focusing on the gathering, transportation, and storage of NGLs and crude oil, natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Prior to joining Regency Energy Partners LP, Mr. Chen served in various roles with the assurance and business advisory services practice of PricewaterhouseCoopers LLP from 2003 to 2009. Mr. Chen is a Certified Public Accountant.

Forgan McIntosh. Forgan McIntosh has served as the Senior Vice President—Commercial and Corporate Development of our general partner since September 2015 and served as Vice President—Corporate Development of our general partner since November 2012.  Mr. McIntosh was an Associate at Barclays Capital Inc. within the Global Power & Utilities investment banking group from August 2010 to October 2012. Prior to Barclays, Mr. McIntosh was a Summer Associate at ArcLight Capital Partners, LLC in 2009. From 2000 to 2008, Mr. McIntosh held various positions at early- to mid-stage energy, technology and healthcare companies. Mr. McIntosh holds a Bachelor of Arts from Bates College and a Master of Business Administration from the MIT Sloan School of Management.

Cory Willis. Cory Willis has served as the Senior Vice President—Terminals and Distribution of our general partner since September 2015 and served as Vice President—Natural Gas Liquids of our general partner from March 2015 to September 2015.  Mr. Willis provided independent consulting services to clients engaged in the acquisition, development, and operation of energy assets from October 2013 to February 2015.  From September 2012 to September 2013, Mr. Willis was the Vice President, Asset Management — West for Atlantic Power Corporation.  Mr. Willis joined Atlantic Power as Director, Asset Management in March 2011 and was Atlantic Power’s Vice President and Chief Administrative Officer from June 2011 through September 2012, leading the company’s Human Resources, Information Technology, and Environmental Health & Safety functions. From 2003 through February 2011, Mr. Willis worked for Goldman Sachs & Co. and its Cogentrix Energy subsidiary in various positions, including as Vice President, Development & Asset Management. Mr. Willis holds a Bachelor’s Degree in Information and Operations Management from Texas A&M University.

John F. Erhard. John F. Erhard was named a member of the board of directors of our general partner in July 2011 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Erhard, a Partner at ArcLight, joined the firm in 2001 and has 15 years of energy finance and private equity experience. Prior to joining ArcLight, he was an Associate at Blue Chip Venture Company, a venture capital firm focused on the information technology sector. Mr. Erhard began his career at Schroders, where he focused on mergers and acquisitions. Mr. Erhard earned a Bachelor of Arts in Economics from Princeton University and a Juris Doctor from Harvard Law School. Mr. Erhard previously served on the board of directors of Patriot Coal and on the board of directors of Buckeye GP Holdings (NYSE: BGH), the publicly traded general partner of Buckeye Partners (NYSE: BPL). In addition, Mr. Erhard has experience in the master limited partnership sector. He is currently serving on the board of directors of the general partner of American Midstream Partners, L.P. (NYSE: AMID) and previously served on the board of directors of Buckeye GP Holdings. We believe that Mr. Erhard’s considerable energy, finance and private equity experience, including his experience with master limited partnerships, provide him with the necessary skills to be a member of the board of directors of our general partner.

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Daniel R. Revers. Daniel R. Revers was named a member of the board of directors of our general partner in June 2011 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Revers is Managing Partner of and a co-founder of ArcLight Capital Partners, LLC and has 25 years of energy finance and private equity experience. Mr. Revers manages the Boston office of ArcLight and is responsible for overall investment, asset management, strategic planning, and operations of ArcLight and its funds. Prior to forming ArcLight in 2000, Mr. Revers was a Managing Director in the Corporate Finance Group at John Hancock Financial Services, where he was responsible for the origination, execution, and management of a $6 billion portfolio consisting of debt, equity, and mezzanine investments in the energy industry. Prior to joining John Hancock in 1995, Mr. Revers held various financial positions at Wheelabrator Technologies, Inc., where he specialized in the development, acquisition, and financing of domestic and international power and energy projects. In addition, Mr. Revers is currently serving on the board of directors of the general partner of American Midstream Partners, L.P. (NYSE: AMID) and the board of directors of the general partner of TransMontaigne Partners L.P. (NASDAQ: TLP). Mr. Revers also serves in various capacities for a number of not-for-profit organizations, currently serving on the Board of Overseers at the Amos Tuck School of Business Administration and the board of directors of the Citizen Schools. Mr. Revers earned a Bachelor of Arts in Economics from Lafayette College and a Master of Business Administration from the Amos Tuck School of Business Administration at Dartmouth College. We believe that Mr. Revers’ significant energy, finance and private equity experience provide him with the necessary skills to be a member of the board of directors of our general partner.

Evan M Schwartz. Evan M. Schwartz was named a member of the board of directors of our general partner in September 2015 and was appointed to the board in connection with his affiliation with ArcLight, which controls our general partner. Mr. Schwartz is a Director at ArcLight, where he has worked since 2011, and has more than eight years of experience in energy finance.  Prior to joining ArcLight, Mr. Schwartz worked at DC Energy and McKinsey & Company. Mr. Schwartz is a CFA charterholder and holds a Bachelor of Arts in Chemistry and Physics from Harvard University and a Master of Business Administration from the MIT Sloan School of Management. Mr. Schwartz was selected to serve as a director of the board due to his affiliation with ArcLight, his in-depth knowledge of the energy industry and his financial and business expertise.

Greg Arnold. Greg Arnold was named to the board of directors of our general partner in November 2012 and was appointed to the board in connection with the acquisition of our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012. Mr. Arnold has over 25 years of midstream and downstream refined products experience. Mr. Arnold is currently the President, CEO and Chairman of the board of directors of Truman Arnold Companies, a privately owned national petroleum marketing and aviation fixed-based operation company, where he has been since 1987. Mr. Arnold was named President and Chief Operation Officer of Truman Arnold Companies in 1990 and was named President and Chief Executive Officer in 2003. Mr. Arnold has previously served on the board of directors of Century Bancshares, Inc. from 1998 until December of 2008. Additionally, Mr. Arnold served on the board of Christus St. Michael Hospital board prior to 2009. Mr. Arnold received a Bachelor of Business Administration from Stephen F. Austin University. We believe that Mr. Arnold’s significant energy industry and financial experience provide him with the necessary skills to be a member of the board of directors of our general partner.

T. Porter Trimble. T. Porter Trimble was named to the board of directors of our general partner in October 2014. Mr. Trimble founded Fleur de Lis Energy, L.L.C., a private firm specializing in direct investments in upstream oil and gas assets, in January 2014 and has served as its President since founding. From 2008 until December 2013, Mr. Trimble served as Vice Chairman of Merit Energy Company, a private firm specializing in direct investments in oil and gas assets. Between 2004 and 2008, Mr. Trimble was an Executive Vice President at Merit, in which role he was responsible for the oversight and implementation of Merit’s acquisition strategy and the articulation of that strategy to investors. Mr. Trimble has been directly involved in the purchase of over $6.0 billion in oil and gas assets while at Merit and served as a member of its board of directors and its audit committee from 2004 until December 2013. Prior to joining Merit in 1992, Mr. Trimble was with Graham Resources, Inc. in various acquisition and operational positions, and, before that, was in drilling operations for Amoco Production Company in the Gulf of Mexico. Mr. Trimble holds a Bachelor of Science degree in Petroleum Geology from Louisiana State University and a Master of Engineering degree in Petroleum Engineering from Tulane University. We believe that Mr. Trimble’s significant energy industry experience, particularly his acquisition strategy and upstream oil and gas expertise, provides him with the necessary skills to be a member of the board of directors of our general partner.

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Norman J. Szydlowski. Norman J. Szydlowski was named to the board of directors of our general partner in October 2014. From April 2014 through September 2014, Mr. Szydlowski managed his personal investments as a private investor. Mr. Szydlowski served as President and Chief Executive Officer and Chairman of the board of directors of Rose Rock Midstream GP, LLC from December 2011 to April 2014. Mr. Szydlowski also served as a director and as President and Chief Executive Officer of SemGroup Corporation from November 2009 to April 2014 and as a director of NGL Energy Partners from November 2011 to April 2014. From January 2006 until January 2009, Mr. Szydlowski served as President and Chief Executive Officer of Colonial Pipeline Company, an interstate common carrier of petroleum products. From 2004 to 2005, he served as a senior consultant to the Iraqi Ministry of Oil in Baghdad on behalf of the U.S. Department of Defense, where he led an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served as vice president of refining for Chevron Corporation (formerly ChevronTexaco), one of the world’s largest integrated energy companies. Mr. Szydlowski joined Chevron in 1981 and served in various capacities of increasing responsibility in sales, planning, supply chain management, refining and plant operations, transportation and construction engineering. In addition, Mr. Szydlowski serves on the board of directors of the general partner of Transocean Partners LLC (NYSE: RIGP) and the board of directors of the general partner of 8point3 Energy Partners, LP (NASDAQ: CAFD). We believe that Mr. Szydlowski’s significant energy industry experience provides him with the necessary skills to be a member of the board of directors of our general partner.

Josh L. Sherman. Josh L. Sherman was named to the board of directors of our general partner in January 2015. Mr. Sherman is a partner at Opportune LLP (“Opportune”), an independent consultancy focused exclusively on the energy industry. Since January 2008, Mr. Sherman has been the partner in charge of the Complex Financial Reporting group of Opportune and previously held the title of managing director from June 2006 through December 2007. Mr. Sherman has over 16 years of experience with the technical aspects of financial reporting, SEC filings, valuation and financial due diligence assistance. Prior to working with Opportune, Mr. Sherman was employed as a director with Sirius Solutions LLLP, where he provided energy consulting services from September 2002 to June 2006. Mr. Sherman worked in the audit and global energy markets departments with Deloitte & Touche from January 1997 to August 2002, where he managed the audits of regulated gas and electric utilities, independent power producers and energy trading entities. A Certified Public Accountant and a member of the American Institute of Certified Public Accountants and the National Association of Corporate Directors, Mr. Sherman holds a BBA and a Masters in Accountancy from the University of Texas. Mr. Sherman currently serves on the board of directors of Trans Energy, Inc., where he is also chairman of the Audit Committee, chairman of the Compensation Committee and a member of the Governance Committee. Mr. Sherman previously served on the board of directors of Voyager Oil & Gas (Emerald Oil). Based on the attributes, education, and experience requirements set forth in the rules of the SEC and the NYSE, the Board has determined that Mr. Sherman qualifies as an “Audit Committee Financial Expert.” We believe that Mr. Sherman’s extensive energy, audit and financial reporting experience provide him with the necessary skills to be a member of the board of directors of our general partner.

Board Leadership Structure

The president and chief executive officer of our general partner currently serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated operating agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by the members of our general partner, including Lonestar and certain members of management. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines provides that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

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ITEM 11. EXECUTIVE COMPENSATION.

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business. Our general partner, under the direction of its board of directors, is responsible for managing our operations and employs all of the employees that operate our business. The compensation payable to the officers of our general partner is paid by our general partner and such payments are reimbursed by us. For more information please read “Our Partnership Agreement—Reimbursement of Expenses.” However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this Compensation Discussion and Analysis.

This Compensation Discussion and Analysis provides an overview and analysis of (i) the elements of our compensation program for our named executive officers, or NEOs, identified below, (ii) the material compensation decisions made under that program and reflected in the executive compensation tables that follow this Compensation Discussion and Analysis and (iii) the material factors considered in making those decisions. Our general partner intends to provide our NEOs with compensation that is significantly performance based. Our executive compensation program is designed to align executive pay with our performance on both short and long-term bases, link executive pay to the creation of value for unitholders and utilize compensation as a tool to assist us in attracting and retaining the high-caliber executives that we believe are critical to our long-term success.

The primary elements of our executive compensation program and their corresponding objectives are identified in the following table.

Compensation Element	Primary Objective
Base salary	Recognize performance of job responsibilities and attract and retain individuals with superior talent.
Annual performance-based compensation	Promote near-term performance and reward individual contributions to our business on an annual basis.
Discretionary long-term equity incentive awards	Emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership and value creation in our partnership.
Retirement savings (401(k)) plan	Provide an opportunity for tax-efficient savings and long term financial security.
Other elements of compensation and perquisites	Attract and retain talented executives in a cost-efficient manner by providing benefits with high perceived values at relatively low cost.

To serve the foregoing objectives, our overall executive compensation program is generally designed to be flexible rather than formulaic. Our compensation decisions for our NEOs in fiscal 2015 are discussed below in relation to each of the above-described elements of our compensation program. The below discussion is intended to be read in conjunction with the executive compensation tables and related disclosures that follow this Compensation Discussion and Analysis.

For the year ended December 31, 2015, our NEOs were:

· J. Patrick Barley, our Executive Chairman, President and Chief Executive Officer;

· Patrick Welch, our Executive Vice President and Chief Financial Officer;

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· Jon Hanna, our Executive Vice President—Crude Oil, Pipelines and Storage;  

· Shiming Chen, our Senior Vice President and Chief Accounting Officer;

· Forgan McIntosh, our Senior Vice President—Commercial and Corporate Development; and

· Jeremiah Ashcroft, our former Executive Vice President and Chief Operating Officer. Mr. Ashcroft resigned effective August 4, 2015.

Compensation Overview

Our overall compensation program is structured to attract, motivate and retain highly qualified executive officers by paying them competitively, consistent with our success and their contribution to that success. We believe compensation should be structured to ensure that a significant portion of compensation opportunity will be related to factors that directly and indirectly influence unitholder value. Consistent with our performance-based philosophy, we provide a base salary to our NEOs and significant incentive-based compensation opportunity, which includes variable awards under our annual incentive bonus program.

In 2015, our general partner made annual grants of equity-based awards as a means of compensating our executives. Equity-based awards were granted to each of our NEOs in 2015, and we believe that equity participation by our NEOs is an important component of NEO pay.

Determination of Compensation Awards

The compensation committee of the board of directors of our general partner, or the Compensation Committee, is provided with the primary authority to determine and approve the compensation awards available to our NEOs and is charged with reviewing our executive compensation policies and practices to ensure (i) adherence to our compensation philosophies and (ii) that the total compensation paid to our NEOs is fair, reasonable and competitive, taking into account our position within our industry and the level of expertise and experience of our NEOs in their positions. As a result, the Compensation Committee periodically (i) reviews each NEO’s base salary, (ii) assesses the performance of the Chief Executive Officer and other NEOs for each applicable performance period and (iii) determines the amount of awards to be paid to our Chief Executive Officer and other NEOs under our annual bonus incentive program for each year. In making compensation and performance determinations for our NEOs other than our CEO, the Compensation Committee will consider the recommendations of our CEO. Additionally, on a historical basis, performance determinations for our NEOs have been made in a subjective and discretionary manner without regard to pre-determined financial, operational or other performance goals or metrics. However, in the future, we expect that the Compensation Committee may establish annual incentive programs that include the consideration of objective performance-based goals or metrics.

In determining compensation levels for our NEOs, our general partner considers each NEO’s unique position and responsibility and relies upon the judgment and industry experience of its members, including their knowledge of competitive compensation levels in our industry. We believe that our NEOs’ base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace and adjusted for financial and operating performance and previous work experience. In this regard, each NEO’s current and prior compensation, including compensation paid by the NEO’s prior employer, is considered as a reference point against which determinations are made as to whether increases are appropriate to retain the NEO in light of competition or in order to provide continuing performance incentives.

At the request of our board of directors, our Vice President — Human Resources reviewed and provided input on the compensation of our NEOs, trends in executive compensation, meeting materials prepared for and circulated to our board of directors and management’s proposed executive compensation plans.

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While we do not apply rigid formulas in determining the amount and mix of compensation elements, we consider long-term Company performance trends and review each element of compensation as described in this Annual Report on Form 10-K in evaluating and approving the total compensation of each of our NEOs.  We use an internal Certified Compensation Professional (CCP) to perform market studies.  External surveys are used to benchmark similar NEO positions and the scope of these positions by comparing total compensation in a similar industry, revenue size and geographic location.  Surveys used for 2015 compensation studies are Economic Resources Institute (ERI) and Aon/Hewitt 2015 U.S. Total Compensation Measurement Executive Survey. We do not benchmark compensation for our NEOs at any particular percentile of the companies included in these surveys; rather the Compensation Committee considered a variety of factors in making compensation decisions, as discussed throughout this compensation discussion and analysis.  In general, we maintain and incorporate flexibility into our compensation programs and in the assessment process to respond to and adjust for the evolving business environment and individual performance.

Base Compensation for 2015

We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions with similar responsibilities in our marketplace. Historically, base salaries for our NEOs were initially set at modest levels, primarily due to our limited operating history at the time such salaries were determined, and, for our NEOs who were then employed, were increased significantly in 2013 in anticipation of our 2014 initial public offering.  Going forward, we set base salaries for our NEOs generally at a level we deem necessary to attract and retain individuals with superior talent.  For Messrs. Welch, Ashcroft and Hanna, who commenced their employment relationship with our general partner in 2014, base salaries, along with other compensation items, were established based on arms-length negotiations at the time of hire. Each year we determine base salary increases, if any, based upon the performance of our NEOs as assessed by the Compensation Committee and based upon market conditions, and for NEOs other than the Chief Executive Officer, in conjunction with the recommendations made by the Chief Executive Officer.  Following the Compensation Committee’s review of our CCP’s market study analysis, the Compensation Committee determined to increase the base salary of certain of our NEOs, as set forth in the table below, effective as of March 29, 2015, in the case of Messrs. Hanna and McIntosh, and effective as of June 28, 2015, in the case of Mr. Chen. These increases were made to better align our NEOs’ pay with competitive levels in our industry and to reflect new responsibilities associated with certain of our NEOs positions.

	Prior Base	Current Base	Increase in
Name	Salary ($)	Salary ($)	Salary ($)
J. Patrick Barley	425,000	425,000	—
Patrick Welch	400,000	400,000	—
Jon Hanna	300,000	310,500	10,500
Shiming Chen	240,000	300,000	60,000
Forgan McIntosh	200,000	250,000	50,000
Jeremiah Ashcroft	425,000	N/A(1)	N/A(1)

(1) Mr. Ashcroft resigned from his position in August 2015.

Annual Performance-Based Compensation for 2015

We structure our compensation programs to reward executive officers based on our performance and the individual executive’s relative contribution to that performance. Each of our NEOs participates in our annual bonus program, under which cash incentive awards are determined annually in the discretion of the Compensation Committee of the board of directors of our general partner. In making individual annual bonus decisions, the Compensation Committee of the board of directors of our general partner has not historically relied on pre-determined performance goals or targets and did not do so for 2015. Instead, determinations regarding annual bonus compensation awards have been based on a subjective assessment of all reasonably available information, including the applicable executive’s business impact, contributions and leadership, among other factors. The percentage of salary awarded as bonuses to each of our NEOs for 2015 was as follows: Mr. Barley: 50%; Mr. Welch: 37.5%; Mr. Hanna: 25%; Mr. Chen: 50%; and Mr. McIntosh: 20%.  In determining individual award levels, the board of directors of our general partner generally considered on a subjective basis each NEO’s level of authority and responsibility within our organization and their corresponding contributions to our successes for 2015.

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Long-Term Equity Incentive Awards

In 2015, our general partner made annual grants of equity-based awards in the form of phantom units with distribution equivalent rights as a means of compensating our executives, primarily to encourage executive retention, promote a long-term focus and align executive and unitholder interests.

For fiscal year 2015, our general partner granted long-term equity incentive awards to each of our NEOs in the form of phantom units.  Each phantom unit is the economic equivalent of one common unit and is accompanied by a distribution equivalent right entitling the holder to an amount equal to any cash distributions paid in respect of our common units underlying the phantom units. The awards to each of Messrs. Barley, Welch, Hanna, and McIntosh vest in three equal annual installments beginning on the first anniversary of the grant date.  For Mr. Chen, 30,636 of his phantom units vest in three equal annual installments on April 1, 2016, 2017 and 2018 and 4,000 of his phantom units vest on April 1, 2018. The awards to each of our NEOs are subject to continued employment with us on the applicable vesting dates and represent an important element of our efforts to retain these key employees and reward them for strong company performance.

The number of phantom units granted to each of our NEOs in fiscal year 2015 is set forth in the following table.

	Number of
	Phantom
	Units
Name	(#)
J. Patrick Barley	25,000
Patrick Welch	20,000
Jon Hanna	19,000
Shiming Chen	34,636
Forgan McIntosh	9,134
Jeremiah Ashcroft	25,000

Other Elements of Compensation and Perquisites

Our NEOs are eligible under the same plans as all other employees for medical and dental coverage and life and other insurance. We provide these benefits due to their relatively low cost and the high value they provide in attracting and retaining talented executives. Our NEOs do not receive any tax gross up in connection with our provision of these benefits. In addition, for 2015, our general partner provided certain perquisites to Mr. Welch in the form of housing and commuting expenses, primarily related to his long-distance commuting requirements from his personal residence in Colorado to our executive offices pursuant to his employment offer letter agreement. Mr. Welch receives a tax gross up in connection with the provision of his housing and commuting expenses.

Employment Agreements

Our general partner considers the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their “at-will” employment with us may result in the departure or distraction of management personnel to our detriment. Accordingly, with respect to our NEOs, our general partner has entered into employment agreements with each of Mr. Welch, Mr. Ashcroft and Mr. Chen to encourage the continued attention and dedication of these members of our management and to allow them to focus on the value to unitholders of strategic alternatives without concern for the impact on their continued employment. Mr. Ashcroft resigned from his employment with us in August 2015.

Agreements with Mr. Welch, Mr. Ashcroft and Mr. Chen.   In September 2014, our general partner entered into employment agreements with each of Mr. Welch and Mr. Ashcroft, and, in September 2015, our general partner entered into an employment agreement with Mr. Chen.  The agreements with Mr. Welch and Mr. Ashcroft have a three-year initial term and are subject to automatic annual renewal thereafter unless either party gives the other a notice of non-

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extension at least 60 days prior to the expiration of the then-applicable term, and the agreement with Mr. Chen has a three-year term. The agreements provided for an annual base salary of $400,000 for Mr. Welch, $425,000 for Mr. Ashcroft and $300,000 for Mr. Chen, subject to review and adjustment from time to time. In addition, the agreements provide for the executives to participate in the bonus and benefit plans maintained by our general partner from time to time. If our general partner terminates Mr. Welch’s, Mr. Ashcroft’s or Mr. Chen’s employment for cause or due to death or disability or if the executive resigns his employment without good reason, then he will receive only his base salary earned through the date of termination but not yet paid, any expenses owed to him and any amount accrued arising from his participation in employee benefit plans or as required by law and, solely in the event of a termination of employment due to disability or death, continued payment of the executive’s base salary through the end of the third or first month, respectively, following termination. Any further right to salary, bonus or other benefits will cease. Pursuant to Mr. Welch’s and Mr. Ashcroft’s employment agreements, if Mr. Welch’s or Mr. Ashcroft’s employment is terminated by our general partner without cause or he resigns for good reason during the term of the employment agreement and, in either case, signs a release of claims in favor of our general partner, then he will be entitled to receive, as severance payments, an amount equal to one year of the executive’s base salary plus an amount equal to the average of the executive’s annual bonus received during the three most recent fiscal years (or if the executive was not employed with our general partner over the full three most recent fiscal years, his target bonus will be substituted for the year in which he was not employed for purposes of determining the average bonus), plus an amount equal to the executive’s healthcare continuation COBRA premiums for twelve months. If such termination occurs within six months after a change in control of us or our general partner, the severance amount would be two times the executive’s base salary and bonus amount and the healthcare continuation period would be 24 months. Pursuant to Mr. Chen’s employment agreement, if Mr. Chen’s employment is terminated by our general partner without cause or he resigns for good reason during the term of the employment agreement and, in either case, signs a release of claims in favor of our general partner, then he will be entitled to receive, as severance payments, an amount equal to one year of his base salary. 

In addition, upon termination of employment, the employment agreements for each of Mr. Welch, Mr. Ashcroft and Mr. Chen provide that the executive (i) will not engage in any business that is competitive with us in the geographical locations where we operate for a period of at least 12 months following termination and (ii) will not solicit our employees, customers, suppliers or other business associates for a period of two years following termination.

For purposes of the employment agreements described above, “Cause” is defined generally as (i) fraud, embezzlement or theft against us or our general partner or a material violation of company policies, (ii) gross negligence, dishonesty or fraud causing material harm to us or our general partner or any conviction of, or guilty plea or nolo contendere plea to, or confession of, a Class A-type felony or felony involving moral turpitude or other crime involving moral turpitude, (iii) unauthorized disclosure or misuse of our confidential information, (iv) material nonperformance of duties, willful misconduct or breach of fiduciary duty that is not cured within 10 days after notice to the executive thereof, (v) use of illegal drugs at work, or (vi) a material breach of the employment agreement. “Good reason” is defined generally as (i) a material and adverse diminution in job title or duties, (ii) a material breach of our general partner’s obligations under the agreement (including a failure to pay or provide salary or benefits), (iii) a greater than 50 mile relocation of the executive’s primary place of employment, or (iv) a material reduction in the executive’s base salary (generally requiring a 10% or greater reduction), in each case that is not cured within 30 days of the executive’s objection thereto.

In connection with his commencement of employment with our general partner, Mr. Ashcroft was entitled to a signing bonus in the amount of $1,200,000 to be paid in four installments as follows: $200,000 within 30 days of commencing employment; $600,000 upon commencement of our initial public offering; and $200,000 on each of January 31, 2015 and 2016, conditional upon his continued employment with us. Mr. Ashcroft resigned from his employment with us in August 2015 and forfeited the final installment of his signing bonus.

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Summary Compensation Table for 2015

The following table sets forth certain information with respect to the compensation paid to our NEOs for the year ended December 31, 2015.

				Unit	All Other
Name and Principal Position	Year	Salary($)(1)	Bonus($)(2)	Awards($)(3)	Compensation($)(4)	Total($)
J. Patrick Barley	2015	441,346	212,500	276,500	10,600	940,946
President and Chief Executive Officer	2014	425,000	425,000	—	10,400	860,400
	2013	405,769	276,250	—	4,577	686,596
Patrick Welch(5)	2015	415,385	150,000	221,200	110,285	896,870
Executive Vice President and Chief Financial Officer	2014	523,917	300,000	356,080	59,953	1,239,950
	2013	127,200	—	—	20,580	147,780
John Hanna(6)	2015	319,413	77,625	210,140	35,600	642,778
Executive Vice President—Crude Oil, Pipelines and Storage	2014	282,692	220,000	437,088	10,400	950,180
Shiming Chen(7)	2015	279,230	150,000	426,859	9,457	865,546
Senior Vice President and Chief Accounting Officer	2014	214,615	25,200	—	—	239,815
	2013	161,539	67,472	384,010	83,000	696,021
Forgan McIntosh	2015	245,192	50,000	101,022	—	396,214
Senior Vice President—Commercial and Corporate Development	2014	194,711	70,000	—	—	264,711
	2013	175,000	100,000	—	79,069	354,069
Jeremiah Ashcroft(8)	2015	302,403	—	276,500	10,382	589,285
Executive Vice President and Chief Operating Officer	2014	286,057	1,225,000	890,200	—	2,401,257

(1) The Partnership pays payroll on a bi-weekly basis. The amounts shown in the table above as 2015 salary exceed the NEOs’ regular annual salary amount because they reflect 27 (rather than the usual 26) pay periods that occured during 2015.

(2) The 2015 bonus amounts reflect bonuses paid in early 2016 that relate to services performed in 2015 and represent the awards earned under our annual incentive bonus program. For additional information, please read “—Annual Performance-Based Compensation for 2015” above. For Mr. Ashcroft, (a) the amount shown in 2014 also represents a relocation bonus of $50,000 and a signing bonus of $800,000 and (b) the amount shown in 2015 represents a retention bonus of $200,000, in each case, granted to Mr. Ashcroft in connection with his commencement of employment in April 2014. For Mr. Hanna, the amount shown in 2014 also represents a signing bonus of $175,000 granted to Mr. Hanna in connection with his commencement of employment in January 2014. For additional information, please read “Employment Agreements” above.

(3) Amounts shown for 2015 represent the aggregate grant-date fair value of phantom units granted during 2015 computed in accordance with ASC Topic 718, excluding the effect of estimated forfeitures.  Amounts shown for 2014 represent the aggregate grant-date fair value of restricted class B common units granted during 2014 computed in accordance with ASC Topic 718, excluding the effect of estimated forfeitures.

(4) For Messrs. Barley and Ashcroft, the amount shown reflects company contributions to our 401(k) retirement savings plan. For Mr. Welch, (a) the 2015 amount shown reflects company contributions to our 401(k) retirement savings plan as well as $99,685 for travel and housing costs, including applicable tax gross-up and (b) the 2014 amount shown reflects company contributions to our 401(k) retirement savings plan as well as $33,553 for temporary housing and living assistance, including lodging expenses, and $17,170 for travel and commuting expenses, including ground transportation and airfare costs.  For Mr. Hanna, the 2015 amount shown reflects company contributions to our 401(k) retirement savings plan as well as a $25,000 relocation bonus.  For Mr. Chen, (a) the

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2015 amount shown reflects company contributions to our 401(k) retirement savings plan and (b) the 2013 amount shown reflects a $83,000 signing bonus.  For Mr. McIntosh, the 2013 amount shown reflects company contributions to our 401(k) retirement savings plan and a $65,000 signing bonus.

(5) Mr. Welch commenced employment with us in April 2014 and amounts shown represent compensation earned during 2014 since that time plus the fees we paid to Opportune LLP for Mr. Welch’s service as an outside consultant. Mr. Welch served as an outside consultant and was functionally our Chief Financial Officer from November 2013 to April 2014 pursuant to a consulting agreement that we entered into with Opportune LLP. The compensation in the “Salary” column of the table above for 2014 reflects $243,600 of fees paid to the consulting firm that employed Mr. Welch for his services to us in 2014.

(6) Mr. Hanna commenced employment with us in January 2014, and amounts shown represent compensation earned during 2014 since that time.

(7) Mr. Chen commenced employment with us in February 2013, and amounts shown represent compensation earned during 2013 since that time.

(8) Mr. Ashcroft commenced employment with us in April 2014, and amounts shown for 2014 represent compensation earned during 2014 since that time.  Mr. Ashcroft resigned from his position in August 2015, and amounts shown for 2015 represent compensation earned during 2015 until the date of his resignation.

Grants of Plan-Based Awards for 2015

		All Other Unit Awards:
		Number of
		Phantom	Grant Date Fair
	Grant	Units	Value of Unit
Name	Date	(#)	Awards(1)
J. Patrick Barley	4/1/15	25,000	$	276,500
Patrick Welch	4/1/15	20,000	$	221,200
Jon Hanna	4/1/15	19,000	$	210,140
Shiming Chen	4/1/15	12,960	$	143,338
	7/6/15	21,676	$	283,522
Forgan McIntosh	4/1/15	9,134	$	101,022
Jeremiah Ashcroft	4/1/15	25,000	$	276,500

(1) Amounts shown represent the aggregate grant-date fair value of phantom units computed in accordance with ASC Topic 718, excluding the effect of estimated forfeitures.

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Outstanding Equity Awards at December 31, 2015

The following table provides information regarding the outstanding unvested unit awards held by our NEOs as of December 31, 2015.

	Unit Awards(6)
	Number of
	Units		Market Value of
	That		Units
	Have Not		That Have
	Vested		Not Vested
Name	(#)		($)
J. Patrick Barley	25,000	(1)	$	123,000
Patrick Welch	20,000	(1)	$	98,400
	13,353	(2)	$	65,697
Jon Hanna	19,000	(1)	$	93,480
	13,353	(3)	$	65,697
Shiming Chen	34,636	(5)	$	170,409
	2,225	(4)	$	10,947
Forgan McIntosh	9,134	(1)	$	44,939
Jeremiah Ashcroft	—			—

(1) The phantom units vest in three equal annual installments on the first, second and third anniversaries of the applicable date of grant, subject to the NEO’s continued service with us on each applicable vesting date.

(2) Amount shown represents 2,628 common units and 10,725 subordinated units. The units vest in three equal annual installments on each of April 7, 2016, 2017 and 2018, subject to the NEO’s continued service with us on each applicable vesting date.

(3) Amount shown represents 2,628 common units and 10,725 subordinated units. The units vest in three equal annual installments on each of January 6, 2016, 2017 and 2018, subject to the NEO’s continued service with us on each applicable vesting date.

(4) Amount shown represents 438 common units and 1,787 subordinated units. The units vest on December 5, 2016, subject to the NEO’s continued service with us on each applicable vesting date.

(5) For Mr. Chen, (i) 30,636 of his phantom units vest in three equal annual installments on April 1, 2016, 2017 and 2018 and (ii) 4,000 of his phantom units vest on April 1, 2018, in each case, subject to Mr. Chen’s continued service with us on each applicable vesting date.

(6) Common and subordinated unit awards in the table above reflect the conversion of Class B common units into common and subordinated units in us in connection with our IPO.

Units Vested in 2015

The following table sets forth the number and value of common and subordinated unit awards that vested for the NEOs during 2015.

	Unit Awards
		Number of
	Number of Units	Subordinated Units
	Acquired on	Acquired on Vesting	Value Realized on
Name	Vesting (#)	(#)	Vesting ($)(1)
J. Patrick Barley	—	—		—
Patrick Welch	876	3,575	$	53,011
Jon Hanna	876	3,575	$	59,109
Shiming Chen	438	1,787	$	14,463
Forgan McIntosh	438	1,787	$	15,553
Jeremiah Ashcroft	2,190	8,937	$	149,881

(1) Amount shown reflects an estimate of the fair market value of the units as of the vesting date.

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Nonqualified Deferred Compensation and Pension Benefits

None of our NEOs participate in any nonqualified deferred compensation plans or pension plans and received no nonqualified deferred compensation or pension benefits during the year ended December 31, 2015.

Potential Payments upon Termination or Change in Control

Each of Messrs. Welch and Chen have an agreement that provides for severance benefits upon a termination of employment. See “—Employment Agreements” above for a description of the employment and severance agreements for each of our NEOs. Assuming that each of these agreements were in place on December 31, 2015, as applicable, and a termination of employment effective as of December 31, 2015 (i) by our general partner without cause, (ii) due to the executive’s resignation for good reason or (iii) due to the executive’s disability or death, each of our NEOs would have received the following payments and benefits:

						Termination
						Without Cause or
						Resignation
		Termination				for Good
		Without Cause or				Reason
		Resignation			Termination	After a
	Payment	for Good			due to	Change in
Name	Type	Reason($)		Death($)	Disability($)	Control($)
J. Patrick Barley	Salary	n/a		n/a	n/a	n/a
	Bonus	n/a		n/a	n/a	n/a
	Total	n/a		n/a	n/a	n/a
Patrick Welch	Salary	419,687	(1)	33,333	99,999	839,374	(1)
	Bonus	300,000		—	—	600,000
	Total	719,687		33,333	99,999	1,439,374
Jon Hanna	Salary	n/a		n/a	n/a	n/a
	Bonus	n/a		n/a	n/a	n/a
	Total	n/a		n/a	n/a	n/a
Shiming Chen	Salary	300,000		25,000	75,000	300,000
	Bonus	—		—	—	—
	Total	300,000		25,000	75,000	300,000
Forgan McIntosh	Salary	n/a		n/a	n/a	n/a
	Bonus	n/a		n/a	n/a	n/a
	Total	n/a		n/a	n/a	n/a
Jeremiah Ashcroft(2)	Salary	n/a		n/a	n/a	n/a
	Bonus	n/a		n/a	n/a	n/a
	Total	n/a		n/a	n/a	n/a

(1) Salary amount shown includes an estimated amount for healthcare continuation COBRA reimbursement payments of $19,687 per year.

(2) Mr. Ashcroft resigned from his employment with us in August 2015 and did not receive any severance payments or benefits in connection with his resignation.

Compensation Risk

We have analyzed the potential risks arising from our compensation policies and practices, and have determined that there are no such risks that are reasonably likely to have a material adverse effect on us.

Director Compensation

For the year ended December 31, 2015, our NEOs or other employees who also served as members of the board of directors of our general partner did not receive additional compensation for their service as directors. Directors who were not officers, employees or paid consultants or advisors of us or our general partner were eligible to receive the

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following amounts as compensation for their services as directors in 2015 (i) an annual retainer of $50,000; (ii) an additional annual retainer of $10,000 for service as the chair of any standing committee and a $5,000 fee for service on two or more committees; and (iii) meeting attendance fees of $1,750 per meeting attended, whether telephonically or in person.

In 2015, we provided the following compensation to our independent directors:

	Fees Earned or
	Paid in	Unit
Name	Cash ($)	Awards ($)(1)	Total
T. Porter Trimble	149,000	26,920	175,920
Norman J. Szydlowski	137,250	26,920	164,170
Josh Sherman	136,750	26,920	163,670

(1) Reflects the fair market value of the unit awards on the date of grant. As of December 31, 2015, each of Messrs. Trimble, Szydlowski and Sherman held 2,000 unvested phantom units.

Directors also receive reimbursement for out-of-pocket expenses associated with attending board or committee meetings and director and officer liability insurance coverage. Under our partnership agreement, each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law, subject to certain limitations provided in our partnership agreement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth the beneficial ownership of our units held by beneficial owners of 5.0% or more of our common and subordinated units, by each director and director nominee of JP Energy GP II LLC, our general partner, by each named executive officer and by all directors and executive officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants and phantom units held by that person that are currently exercisable or exercisable within 60 days of February 22, 2016, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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The percentage of units beneficially owned is based on a total of 18,467,032 common units and 18,126,511 subordinated units outstanding as of February 22, 2016.

							Percentage
							of Total
							Common
		Percentage			Percentage		Units and
	Common	of Common		Subordinated	of Subordinated		Subordinated
	Units	Units		Units	Units		Units
	Beneficially	Beneficially		Beneficially	Beneficially		Beneficially
Name of Beneficial Owner(1)	Owned	Owned		Owned	Owned		Owned
Lonestar Midstream Holdings, LLC	3,674,187	19.9	%	14,992,654	82.7	%	51.0	%
Clearbridge Investments, LLC(2)	2,024,819	11.0	%	—	—		5.5	%
Goldman Sachs Asset Management, L.P(3).	1,511,583	8.2	%	—	—		4.1	%
Massachusetts Financial Services Company(4)	1,255,544	6.8	%	—	—		3.4	%
Advisory Research, Inc.(5)	1,035,520	5.6	%	—	—		2.8	%
Directors/Named Executive Officers:
J. Patrick Barley(6)	25,996	*		125,122	*		*
Patrick J. Welch(7)	18,439	*		13,354	*		*
Jon E. Hanna(8)	9,265	*		11,966	*		*
Shiming Chen(9)	11,741	*		6,240	*		*
Forgan McIntosh(10)	4,011	*		3,943	*		*
John F. Erhard(11)	—	—		—	—		—
Daniel R. Revers(11)	—	—		—	—		—
Evan M. Schwartz(11)	—	—		—	—		—
Greg Arnold(12)	290,244	1.6	%	1,184,352	6.5	%	4.0	%
T. Porter Trimble	13,166	*		—	—		—
Norman J. Szydlowski	2,166	*		—	—		—
Josh L. Sherman	5,666	*		—	—		—
All directors, director nominees and executive officers as a group (13 persons)	383,194	2.1	%	1,334,794	7.4	%	4.7	%

*Less than 1.0%

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 600 East Las Colinas Boulevard, Suite 2000, Irving, Texas 75039.

(2) As reported on Schedule 13G as of December 31, 2015 and filed with the SEC on February 16, 2016. The address for Clearbridge Investments, LLC is 620 8th Avenue, New York, New York 10018.

(3) As reported on Schedule 13G as of December 31, 2015 and filed with the SEC on February 9, 2016. The address for Goldman Sachs Asset Management, L.P. is 200 West Street, New York, New York 10282.

(4) As reported on Schedule 13G as of December 31, 2015 and filed with the SEC on February 11, 2016. The address for Massachusetts Financial Services Company is 111 Huntington Avenue, Boston, Massachusetts 02199.

(5) As reported on Schedule 13G as of December 31, 2015 and filed with the SEC on February 16, 2016. The address for Advisory Research, Inc. is 180 North Stetson, Chicago, Illinois 60601.

(6) J. Patrick Barley owns and controls substantially all of each of JP Energy GP LLC and CB Capital Holdings II, LLC. Each of JP Energy GP LLC and CB Capital Holdings II, LLC is a member of Lonestar Midstream Holdings, LLC (“Lonestar”) but neither has any investment or voting control over the units held by Lonestar and therefore Mr. Barley disclaims beneficial ownership of the units held by Lonestar. Mr. Barley owns and controls 100% of

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JP Energy Holdings, LLC, which owns 17,663 of our common units and 125,122 of our subordinated units. Also includes 8,333 units that will vest on April 1, 2016.

(7) Includes 6,667 units that will vest on April 1, 2016.

(8) Includes 6,333 units that will vest on April 1, 2016.

(9) Includes 10,212 units that will vest on April 1, 2016.

(10) Includes 3,045 units that will vest on April 1, 2016.

(11) ArcLight Energy Partners Fund V, L.P. (“ArcLight Fund V”) owns and controls, through one of its wholly owned subsidiaries, Lonestar and therefore may be deemed to indirectly beneficially own 3,674,187 of our common units and 14,992,654 of our subordinated units held directly or indirectly by Lonestar. Messrs. Revers, Erhard and Schwartz, each a director of our general partner, are managing partner, partner and principal, respectively, of ArcLight Capital Partners, LLC. ArcLight Capital Parners, LLC is the investment manager of, and ArcLight Capital Holdings, LLC is the managing partner of the general partner of, ArcLight Fund V. The investment committee of ArcLight Capital Partners, LLC generally exercises voting and dispositive power over the units held by Lonestar, with the committee consisting of six members including Messrs. Revers and Erhard. Messrs. Erhard and Schwartz do not have beneficial ownership of the units held by Lonestar. Due to certain voting rights granted to Mr. Revers as a member of ArcLight Capital Partners, LLC’s investment committee, he may be deemed to indirectly beneficially own the units held by Lonestar, but disclaims any such ownership except to the extent of his pecuniary interest therein. The address for each of Messrs. Revers, Erhard, and Schwartz is 200 Clarendon Street, 55th Floor, Boston, MA 02116.

(12) Mr. Arnold indirectly owns 100% of Arkansas Terminaling & Trading, Inc, which owns 290,244 of our common units and 1,184,352 of our subordinated units. The address for Mr. Arnold is 100 Crescent Ct., Suite 1600, Dallas, Texas 75201.

The following table summarizes the number of securities remaining available for future issuance under the LTIP as of December 31, 2015:

			Number of securities
			remaining available for
			future issuance under
	Number of securities to		equity compensation
	be issued upon exercise	Weighted-average	plans (excluding
	of outstanding options,	exercise price of	securities reflected in
	warrants and rights	outstanding options,	column (a))
Plan Category	(a)	warrants and rights (b)	(c)
Equity compensation plans approved by security holders:
N/A	—	—	—
Equity compensation not approved by security holders
2014 Long-Term Incentive Plan (1)	392,420	—	3,242,030
Total	392,420	—	3,242,030

(1) The LTIP was adopted by our general partner in October 2014 in connection with our IPO and did not require approval by our unitholders. The LTIP contemplates the issuance or delivery of up to 3,642,700 common units to satisfy awards under the LTIP. The material features of the LTIP are described in our prospectus filed pursuant to Rule 424(b)(4) with the SEC on October 2, 2014 under “Management—Determination of Compensation Awards—2014 Long-Term Incentive Plan.”

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

As of February 22, 2016, our general partner and its affiliates, including Lonestar, owned 4,020,291 common units and 16,327,448 subordinated units representing a 55.7% limited partner interest in us. In addition, our general partner owned a non-economic general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and liquidation (if any) of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates in connection with the IPO	4,032,636 common units;
	16,455,318 subordinated units;
	a non-economic general partner interest;
	the incentive distribution rights; and
	a distribution of $83.2 million in accounts receivable.

Operational Stage

Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions of 100.0% to the unitholders pro rata, including our general partner and its affiliates, as holders of an aggregate of 4,020,291 common units and 16,327,448 subordinated units. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level. Our general partner will not receive distributions on its non-economic general partner interest.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $26.5 million on their common units and subordinated units.
Payments to our general partner and its affiliates	Our general partner does not receive a management fee or other compensation for its management of us. However, we reimburse our general partner and its affiliates for all expenses incurred on our behalf. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner’s employees and executive officers who perform services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

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Withdrawal or removal of our general partner If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

Liquidation Upon our liquidation, the partners will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements With Affiliates in Connection With the IPO

Right of First Offer Agreement

We and our general partner entered into a Right of First Offer Agreement (the “ROFO agreement”) with JP Development and an affiliate of ArcLight Fund V (“ArcLight Fund V”) at the closing of the IPO. The ROFO agreement contains the terms and conditions upon which (i) JP Development granted us a right of first offer with respect to all of the current and future assets of JP Development and its subsidiaries (each, a “Development entity”) and (ii) ArcLight Fund V granted us a right of first offer with respect to a 50% indirect interest in Republic (clauses (i) and (ii) are collectively referred to as the “ROFO Assets”). The ROFO agreement has a primary term of five years with respect to the current and future assets of JP Development and has a primary term of eighteen months with respect to the 50% indirect interest in Republic. The ROFO Agreement may be extended for subsequent annual periods by written agreement prior to its expiration.

The ROFO agreement’s right of first offer provides that if any Development entity or ArcLight Fund V proposes to transfer any ROFO Asset to a non-affiliated third party, then such Development entity or ArcLight Fund V, as the case may be, must give us notice of its intent to make a transfer and include in the notice the material terms and conditions of the transfer. Following receipt of the notice, we will have (x) 60 days (for notices delivered by Development) or (y) 30 days (for notices delivered by ArcLight Fund V) to propose an offer which will contain the terms on which we propose to acquire the ROFO Asset that is the subject of the proposed transfer. Our offer will be subject to approval by the conflicts committee of the board of directors of our general partner. If we do not propose an offer within such 60-day or 30-day period, as applicable, we will be deemed to have waived our right of first offer with respect to the proposed transfer of the subject ROFO Asset. If we propose an offer within the specified time period, we and JP Development or ArcLight Fund V, as applicable, will be required to engage in good faith negotiations for up to 30 days with respect to the terms and conditions upon which the subject ROFO Asset will be sold to us. If we and JP Development or ArcLight Fund V, as the case may be, are unable to agree to the terms of a purchase and sale of the subject ROFO Asset within such 30 day period, the Development entity or ArcLight Fund V, as the case may be, will be permitted to transfer the subject ROFO Asset to a third party (i) on terms no more favorable to such third party than those set forth in the last written offer proposed by us during negotiations between us and JP Development pursuant to the ROFO Agreement and (ii) at a price equal to no less than 100% of the price offered by us in such last written offer.

Other Transactions With Related Persons

JP Development

We perform certain management services for JP Development pursuant to a services agreement in exchange for a monthly fee of $50,000,which is subject to an adjustment each month to accurately reflect the degree and extent of the services provided. For the year ended December 31, 2015, we received $828,000 of fees from JP Development.

JP Development had a pipeline transportation business that provided crude oil pipeline transportation services to our discontinued Mid-Continent Business. As a result of utilizing JP Development’s pipeline transportation services, we incurred pipeline tariff fees of $6,023,000 for the year ended December 31, 2015.

102

On February 1, 2016, we completed the sale of our crude oil supply and logistics operations in the Mid-Continent region of Oklahoma and Kansas to JP Development in connection with JP Development’s sale of its GSPP pipeline assets to a third-party buyer. The sales price was $9,685,000; which included certain adjustments related to inventory and other working capital items.

Refined Products Sale Agreements

Our NGL distribution and sales segment purchased refined products from Truman Arnold Companies (“TAC”), which directly or indirectly owns a 4.0% limited partner interest in us. During the year ended December 31, 2015, we paid TAC $1,124,000for such products.

Terminal Registration Rights Agreement

In connection with the acquisition of our North Little Rock, Arkansas and Caddo Mills, Texas refined products terminals in November 2012, we entered into a registration rights agreement (the “Terminal registration rights agreement”) with certain of the sellers (the “Terminal Sellers”) where we agreed to grant “piggyback” rights. Pursuant to the terms of the piggyback rights, at any time after the closing of the IPO, in the event that we file a registration statement of any kind for the sale of common units for our own account or the account of another person or if any holder of registrable securities notifies us that it seeks to dispose of such registrable securities in an underwritten offering, we must notify the Terminal Sellers and offer them the opportunity to include their common units in such filing or underwritten offering. In addition, at any time after we become eligible to register our securities on Form S-3 under the Securities Act of 1933, as amended (the “Securities Act”), any one or more of the Terminal Sellers that is a holder of registrable securities is entitled to certain demand rights, whereby they may request that we register such securities for sale under the Securities Act. These demand rights may be exercised on up to two occasions. We are entitled to select the managing underwriter for any registration of securities under the Terminal registration rights agreement. Although we are responsible for all expenses incurred in connection with the filing of any registration statement, any holder seeking to sell registrable securities under the Terminal registration rights agreement must pay certain selling expenses, including underwriting fees, discounts or commissions allocable to the sale of such securities. The Terminal registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses and the registration rights which it grants are subject to certain conditions and limitations. All registrable securities held by the Terminal Sellers and any permitted transferee will be entitled to these registration rights.

Employees of Our General Partner

We ceased having employees in July 2013. Since July 2013, the employees supporting our operations are employees of our general partner and, as such, we reimburse our general partner for our payroll and other payroll-related expenses that it incurs on our behalf.

CAMS Bluewire Technology, LLC

CAMS Bluewire Technology, LLC (“CAMS Bluewire”), an entity in which ArcLight holds a non-controlling interest, provides us with IT support. For the year ended December 31, 2015, we paid CAMS Bluewire $132,000 for IT support and consulting services.

Management Services Agreement with Republic

We perform certain management services for Republic Midstream, LLC, an entity owned by ArcLight, in exchange for a monthly fee of approximately $58,000. In December 2015, this monthly fee increased to approximately $75,000 a month. For the year ended December 31, 2015, we charged feesof$712,000 to Republic Midstream, LLC for these services. During the second quarter of 2015, we began performing crude transportation and marketing services for Republic Midstream, LLC. We charged $3,049,000 for the year ended December 31, 2015 for these crude transportation and marketing services.

103

ArcLight

In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In addition, ArcLight reimbursed us for certain overhead expenses we incurred for the year ended December 31, 2015. The total amounts paid on our behalf or reimbursed to us were $2,568,000 for the year ended December 31, 2015. In addition, during the year ended December 31, 2015, our general partner agreed to absorb $5,500,000 of corporate overhead expenses incurred by us and not pass such expense through to us.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner adopted a written code of business conduct and ethics in connection with our IPO. Under the code of business conduct and ethics, a director is expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Director Independence

Please read “Item 10. Directors, Executive Officers and Corporate Governance—Management of JP Energy Partners LP” and “—Director Independence” which is incorporated by reference into this Item 13.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following sets forth fees billed by PricewaterhouseCoopers LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2015 and 2014:

	Year Ended December 31,
	2015		2014
	(in thousands)
Audit fees (1)	$	1,863	$	5,089
Tax fees (2)		780		601
Other (3)		17		82
Total	$	2,660	$	5,772

(1) Represents fees for professional services provided in connection with (i) the integrated audit of our annual financial statements, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. During the year ended December 31, 2014, fees associated with our IPO totaled approximately $0.6 million. Audit fees also include fees for audit services related to acquisition financial statements included in our registration statement.

(2) Represents fees for professional services provided for tax compliance, tax advice and tax planning.

(3) Represents other fees provided for other valuation services and subscriptions to online accounting guidance tool.

All services provided by our independent registered public accountant are subject to pre-approval by the audit committee of our general partner. The audit committee of our general partner is informed of each engagement of the independent registered public accountant to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent registered public accounting firm.

104

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

	The following documents are filed as part of this report:
1.	Financial Statements. See “Index to Consolidated Financial Statements” on page F-1.
2.	Financial Statement Schedules and Other Financial Information. All financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes included herein.
3.	Exhibits. See “Index to Exhibits.”

105

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2015 and 2014	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	F-5
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2015, 2014 and 2013	F-6
Notes to Consolidated Financial Statements	F-7

F-1

Report of Independent Registered Public Accounting Firm

To the Partners and Unitholders of

JP Energy Partners LP:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ capital and cash flow present fairly, in all material respects, the financial position of JP Energy Partners LP and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2015).  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 29, 2016

F-2

PART IFINANCIAL INFORMATION

Item 1.Financial Statements

JP ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

	December 31,		December 31,
	2015		2014
	(in thousands, except unit data)
ASSETS
Current assets
Cash and cash equivalents	$	1,987	$	3,325
Restricted cash		—		600
Accounts receivable, net		60,519		108,725
Receivables from related parties		8,624		10,548
Inventory		4,786		5,677
Prepaid expenses and other current assets		4,168		4,915
Current assets of discontinued operations held for sale		2,730		15,149
Total Current Assets		82,814		148,939
Non-current assets
Property, plant and equipment, net		291,454		251,690
Goodwill		216,692		240,782
Intangible assets, net		134,432		145,330
Deferred financing costs and other assets, net		3,223		4,711
Noncurrent assets of discontinued operations held for sale		6,644		21,721
Total Non-Current Assets		652,445		664,234
Total Assets	$	735,259	$	813,173
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	45,933	$	88,052
Accrued liabilities		15,260		28,971
Capital leases and short-term debt		107		229
Customer deposits and advances		3,742		5,050
Current portion of long-term debt		454		383
Current liabilities of discontinued operations held for sale		640		—
Total Current Liabilities		66,136		122,685
Non-current liabilities
Long-term debt		162,740		84,125
Other long-term liabilities		1,463		5,683
Total Liabilities		230,339		212,493
Commitments and Contingencies
Partners’ capital
General Partner		5,568		—
Common units (22,119,170 and 21,852,219 units authorized as of December 31, 2015 and 2014, respectively; 18,465,320 and 18,209,519 units issued and outstanding as of December 31, 2015 and 2014, respectively)		266,691		315,630
Subordinated units (18,197,249 units authorized;18,127,678 and 18,197,249 units issued and outstanding as of December 31, 2015 and 2014, respectively)		232,661		285,050
Total Partners’ Capital		504,920		600,680
Total Liabilities and Partners’ Capital	$	735,259	$	813,173

See accompanying notes to consolidated financial statements.

F-3

JP ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2015		2014		2013
	(in thousands, except unit and per unit data)
REVENUES
Crude oil sales	$	455,465	$	470,336	$	164,356
Crude oil sales - related parties		884		—		—
Gathering, transportation and storage fees		25,991		30,762		23,942
Gathering, transportation and storage fees - related parties		2,165		—		—
NGL and refined product sales		170,009		192,804		166,245
NGL and refined product sales - related parties		—		7,419		12,343
Refined products terminals and storage fees		12,362		10,260		10,179
Refined products terminals and storage fees - related parties		—		1,533		2,130
Other revenues		13,709		13,040		11,674
Total revenues		680,585		726,154		390,869
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		527,476		605,682		276,804
Operating expense		69,377		65,584		57,728
General and administrative		45,383		46,362		44,488
Depreciation and amortization		46,852		40,230		30,987
Goodwill impairment		29,896		—		—
Loss on disposal of assets, net		909		1,137		1,492
Total costs and expenses		719,893		758,995		411,499
OPERATING LOSS		(39,308)		(32,841)		(20,630)
OTHER INCOME (EXPENSE)
Interest expense		(5,375)		(8,981)		(8,245)
Loss on extinguishment of debt		—		(1,634)		—
Other income, net		1,732		8		887
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(42,951)		(43,448)		(27,988)
Income tax expense		(754)		(300)		(208)
LOSS FROM CONTINUING OPERATIONS		(43,705)		(43,748)		(28,196)
DISCONTINUED OPERATIONS
Net income (loss) from discontinued operations, including loss on disposal of $7,288 in 2014		(14,951)		(9,275)		13,975
NET LOSS	$	(58,656)	$	(53,023)	$	(14,221)
Net loss attributable to the period from January 1, 2014 to October 1, 2014		—		34,407
Net loss attributable to limited partners	$	(58,656)	$	(18,616)
Basic and diluted loss per unit
Net loss from continuing operations allocated to common units	$	(21,830)	$	(9,460)
Net loss allocated to common units	$	(29,351)	$	(9,293)
Weighted average number of common units outstanding		18,373,594		18,212,632
Basic and diluted net loss from continuing operations per common unit	$	(1.19)	$	(0.52)
Basic and diluted net loss per common unit	$	(1.60)	$	(0.51)
Net loss from continuing operations allocated to subordinated units	$	(21,875)	$	(9,490)
Net loss allocated to subordinated units	$	(29,305)	$	(9,323)
Weighted average number of subordinated units outstanding		18,151,700		18,209,948
Basic and diluted net loss from continuing operations per subordinated unit	$	(1.20)	$	(0.52)
Basic and diluted net loss per subordinated unit	$	(1.61)	$	(0.51)
Distributions declared per common and subordinated unit	$	1.279	$	—

See accompanying notes to consolidated financial statements.

F-4

JP ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(58,656)	$	(53,023)	$	(14,221)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:
Depreciation and amortization		49,133		43,922		36,195
Goodwill impairment		37,835		—		—
Asset impairment		4,970		1,984		—
Derivative valuation changes		(11,340)		12,645		(1,162)
Amortization of deferred financing costs		909		906		1,103
Unit-based compensation expenses		1,309		1,789		948
Loss on disposal of assets		1,028		8,415		1,492
Bad debt expense		1,212		820		855
Loss on extinguishment of debt		—		1,634		—
Non-cash inventory LCM adjustment		—		222		—
Other non-cash items		1,744		434		(378)
Changes in working capital, net of acquired assets and liabilities:
Accounts receivable		47,926		13,307		(26,583)
Receivables from related parties		1,924		(7,806)		(948)
Inventory		13,372		17,501		(18,646)
Prepaid expenses and other current assets		709		(545)		4,340
Accounts payable and other accrued liabilities		(45,168)		(13,078)		30,106
Payables to related parties		—		(1,464)		1,274
Customer deposits and advances		(1,308)		2,328		(493)
Changes in other assets and liabilities		442		166		—
NET CASH PROVIDED BY OPERATING ACTIVITIES		46,041		30,157		13,882
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(71,011)		(56,878)		(26,828)
Acquisitions of businesses		(12,583)		—		(1,003)
Proceeds received from sale of assets		3,917		11,325		96
Change in restricted cash		600		(600)		—
NET CASH USED IN INVESTING ACTIVITIES		(79,077)		(46,153)		(27,735)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving line of credit		130,000		390,800		32,300
Payments on revolving line of credit		(51,000)		(485,357)		(12,150)
Proceeds from note payable to related party		—		—		1,000
Payments on long-term debt		(375)		(4,870)		(4,152)
Payment of related party note payable		—		(1,000)		—
Payments on capital leases		(137)		(162)		(164)
Payments on contingent earnout liabilities		(488)		—		—
Change in cash overdraft		(91)		(295)		386
Payments on financed insurance premium		—		(49)		(5,127)
Debt issuance costs		(6)		(3,193)		(980)
Distributions to unitholders		(47,025)		(91,956)		(17,438)
Issuance of Series D preferred units		—		40,000		—
Redemption of Series D preferred units		—		(42,436)		—
Issuance of common units, net of issuance costs		—		262,638		3,128
Common control acquisition		—		(52,000)		—
Contributions from the Predecessor		—		4,321		12,040
Contributions from general partner		1,218		—		—
Tax withholding on unit-based vesting		(289)		(354)		—
Other		(109)		—		(1,855)
NET CASH PROVIDED BY FINANCING ACTIVITIES		31,698		16,087		6,988
Net change in cash and cash equivalents		(1,338)		91		(6,865)
Cash and cash equivalents balance, beginning of year		3,325		3,234		10,099
Cash and cash equivalents balance, end of year	$	1,987	$	3,325	$	3,234
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest	$	4,527	$	7,179	$	7,063
Cash paid for taxes		450		108		106
Non-cash investing and financing transactions:
Accrued capital expenditures	$	3,796	$	3,628	$	977
Debt funded portion of acquisition		12,475		52,000		—
Acquisitions funded by issuance of units		3,442		267,100		—
Assets acquired under capital lease		—		177		13
Financed insurance premium		—		—		1,420
Contributions from general partner		4,350		—		—

See accompanying notes to consolidated financial statements

F-5

JP ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except unit data)

	Units
	Series D	General			Class A	Class B	Class C
	Preferred	Partner	Common	Subordinated	Common	Common	Common	Total
Balance - January 1, 2013	1,136,364	45	—	—	6,868,004	1,153,505	3,166,667	12,324,585
Issuance of Class B Common Units, net of forfeitures	—	—	—	—	—	53,339	—	53,339
Issuance of Class C Common Units	—	—	—	—	—	—	88,114	88,114
Conversion of Preferred Units to Class A Common Units	(1,136,364)	—	—	—	1,136,364	—	—	—
Balance - December 31, 2013	—	45	—	—	8,004,368	1,206,844	3,254,781	12,466,038
Issuance of Class A Common Units	—	—	—	—	363,636	—	—	363,636
Issuance of Class B Common Units	—	—	—	—	—	90,000	—	90,000
Common control acquisition	—	—	—	—	12,561,934	—	—	12,561,934
Issuance of Preferred Units	1,928,909	—	—	—	—	—	—	1,928,909
Redemption of Preferred Units	(1,928,909)	—	—	—	—	—	—	(1,928,909)
Recapitalization	—	(45)	4,463,502	18,213,502	(20,929,938)	(1,296,844)	(3,254,781)	(2,804,604)
Issuance of Common Units, net of forfeitures	—	—	13,746,017	—	—	—	—	13,746,017
Forfeiture of Subordinated Units	—	—	—	(16,253)	—	—	—	(16,253)
Balance - December 31, 2014	—	—	18,209,519	18,197,249	—	—	—	36,406,768
Issuance of Common Units	—	—	266,951	—	—	—	—	266,951
Forfeiture of units under LTIP	—	—	(19,400)	(69,571)	—	—	—	(88,971)
Vesting of units under LTIP	—	—	8,250	—	—	—	—	8,250
Balance - December 31, 2015	—	—	18,465,320	18,127,678	—	—	—	36,592,998

	Series D		General						Class A		Class B		Class C		Predecessor
	Preferred		Partner		Common		Subordinated		Common		Common		Common		Capital		Total
	(in thousands)
Balance - January 1, 2013	$	20,966	$	404	$	—	$	—	$	144,534	$	14,247	$	82,864	$	51,138	$	314,153
Contribution from the Predecessor		—		—		—		—		—		—		—		246,987		246,987
Issuance of Class B Common Units, net of forfeitures and tax withholding		—		—		—		—		—		(164)		—		—		(164)
Issuance of Class C Common Units to a related party		—		—		—		—		—		—		3,128		—		3,128
Conversion of Preferred Units to Class A Common Units		(18,660)		—		—		—		18,660		—		—		—		—
Unit-based compensation		—		—		—		—		—		948		—		—		948
Distributions to unitholders		(1,704)		—		—		—		(10,085)		(1,683)		(3,966)		—		(17,438)
Net income (loss)		(602)		—		—		—		(12,357)		(1,982)		(5,220)		5,940		(14,221)
Balance - December 31, 2013	$	—	$	404	$	—	$	—	$	140,752	$	11,366	$	76,806	$	304,065	$	533,393
Contribution from Predecessor		—		—		—		—		—		—		—		4,321		4,321
Issuance of Class A Common Units		—		—		—		—		8,000		—		—		—		8,000
Issuance of Preferred Units		40,000		—		—		—		—		—		—		—		40,000
Redemption of Preferred Units		(40,656)		—		(350)		(1,430)		—		—		—		—		(42,436)
Unit-based compensation		—		—		123		503		—		1,163		—		—		1,789
Common control acquisition		—		(12,727)		—		—		267,067		—		—		(306,340)		(52,000)
Recapitalization		—		12,323		72,405		295,453		(313,481)		(6,268)		(60,432)		—		—
Issuance of units, net of issuance costs, forfeitures and tax withholdings		—		—		252,745		—		—		—		—		—		252,745
Issuance of Subordinated Units, net of issuance costs, forfeitures and tax withholdings		—		—		—		(153)		—		—		—		—		(153)
Distribution to unitholders		—		—		—		—		(75,662)		(4,528)		(11,766)		—		(91,956)
Net loss attributable to the period from January 1, 2014 to October 1, 2014		656		—		—		—		(26,676)		(1,733)		(4,608)		(2,046)		(34,407)
Net loss attributable to the period from October 2, 2014 to December 31, 2014		—		—		(9,293)		(9,323)		—		—		—		—		(18,616)
Balance - December 31, 2014	$	—	$	—	$	315,630	$	285,050	$	—	$	—	$	—	$	—	$	600,680
Unit-based compensation		—		—		941		368		—		—		—		—		1,309
Issuance of units, net of issuance costs, forfeitures and tax withholdings		—		—		3,259		(215)		—		—		—		—		3,044
Distribution to unitholders		—		—		(23,788)		(23,237)		—		—		—		—		(47,025)
Contribution from general partner		—		5,568		—		—		—		—		—		—		5,568
Net loss		—		—		(29,351)		(29,305)		—		—		—		—		(58,656)
Balance - December 31, 2015	$	—	$	5,568	$	266,691	$	232,661	$	—	$	—	$	—	$	—	$	504,920

See accompanying notes to consolidated financial statements.

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JP ENERGY PARTNERS LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Business and Basis of Presentation

Business.  The consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries. All expressions of the “Partnership”, “JPE”, “us”, “we”, “our”, and all similar expressions are references to JP Energy Partners LP and our consolidated, wholly-owned subsidiaries, unless otherwise expressly stated or the context requires otherwise. We were formed in May 2010 by members of management and were further capitalized in June 2011 by ArcLight Capital Partners, LLC (“ArcLight”) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. JP Energy GP II LLC (“GP II”) is our general partner.

JP Development.On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership (“JP Development”), for the express purpose of supporting JPE’s growth. Since its formation, JP Development had acquired a portfolio of midstream assets that were developed for potential future sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development made the following acquisitions since its formation in July 2012:

On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company (“Parnon Gathering”), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition, Parnon Gathering LLC was renamed to JP Energy Marketing LLC (“JPEM”).

On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH Propane, LLC, an Arkansas limited liability company (“BMH”), which is engaged in the retail and wholesale propane and refined fuel distribution business.

On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil Field Services, Inc., a Texas Corporation (“AOFS”), which is engaged in the crude oil trucking business.

On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability company (“Wildcat Permian”) that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company (“JP Permian”).  JP Permian is engaged in the transportation of crude oil by pipeline.

On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development (“JP Liquids”), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation (“Highway Pipeline”), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.

As a result of the sale of its GSPP pipeline assets (see Note 3), JP Development does not currently hold any material assets.

Common Control Acquisition between JPE and JP Development.  On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, we acquired (i) certain marketing and trucking businesses of JPEM (the “Parnon Gathering Assets”), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the “Dropdown Assets”) from JP Development for an aggregate purchase price of approximately $319.1

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million (the “Common Control Acquisition”), which was comprised of 12,561,934 JPE Class A Common Units and $52 million cash. We financed the cash portion of the purchase price through borrowings under our revolving credit facility.

Basis of Presentation.  Because JPE and JP Development are under common control, we are required under generally accepted accounting principles in the United States (“GAAP”) to account for this Common Control Acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, our balance sheet reflected JP Development’s historical carryover net basis in the Dropdown Assets instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. We also retrospectively recast our financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).

The historical assets and liabilities and the operating results of the Dropdown Assets have been “carved out” from JP Development’s consolidated financial statements using JP Development’s historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. Our recast historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification.  Management believes the assumptions underlying the combined financial statements are reasonable.  However, the combined financial statements do not fully reflect what our, including the Dropdown Assets’ balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under our management during the periods presented. As a result, historical financial information is not necessarily indicative of what our balance sheet, results of operations, and cash flows will be in the future.

JP Development has a centralized cash management that covers all of its subsidiaries.  The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the years ended December 31, 2014 and 2013.  The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity.  The net balances due to us from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.

The total purchase price from the Common Control Acquisition exceeded JP Development’s book value of the net assets acquired. As a result, the excess of the total purchase price over the book value of the assets acquired of $12.7 million was considered a deemed distribution by the general partner and is included as a reduction in general partner interest in Partners’ Capital.

The “predecessor capital” included in Partners’ Capital represents JP Development’s net investment in the Dropdown Assets, which included the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development.  Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled and, as a result, were considered deemed contributions or distributions and are included in JP Development’s net investment.

Net income (loss) attributable to the Dropdown Assets prior to our acquisition of such assets was not available for distribution to our unitholders. Therefore, this income (loss) was not allocated to the limited partners for the purpose of calculating net loss per common unit; instead, the income (loss) was allocated to predecessor capital.

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Initial Public Offering. On October 2, 2014, our common units began trading on the New York Stock Exchange under the ticker symbol “JPEP.” On October 7, 2014, we closed our IPO of 13,750,000 common units at a price of $20.00 per unit.  Prior to the closing of the IPO, the following recapitalization trasactions occurred:

we distributed approximately $92.1 million of accounts receivable that comprised our working capital assets to the existing partners, pro rata in accordance with their ownership interests, of which $72.5 million, $6.0 million and $3.3 million was distributed to Lonestar Midstream Holdings, LLC (“Lonestar”),  Truman Arnold Companies (“TAC”) and JP Development, respectively, all of which are related parties;

each Class A common unit, Class B common unit and Class C common unit (collectively, the “Existing Common Units”) were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and

an aggregate of 18,213,502 Existing Common Units held by the existing partners were automatically converted into 18,213,502 subordinated units representing a 80.3% interest in us prior to the IPO, and a 50.0% interest in us after the closing of the IPO, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the “Remaining Existing Common Units”).

Subsequent to the closing of the IPO, the following recapitalization transactions occurred:

the Remaining Existing Common Units were automatically converted on a one-to-one basis into 4,463,502 common units representing a 12.3% interest in us;

the 45 general partner units in the Partnership held by the general partner were recharacterized as a non-economic general partner interest in us; and

we issued 13,750,000 common units to the public representing a 37.7% interest in us.

We used the proceeds from the IPO of approximately $257.1 million, net of underwriting discounts and structuring fees, to:

pay offering expenses of approximately $2.0 million;

redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million;

repay $195.6 million of the debt outstanding under our revolving credit facility; and

replenish $17.1 million of working capital that was distributed to the then existing partners immediately prior to the IPO.

Immediately following the repayment of the debt outstanding under the our revolving credit facility, we borrowed approximately $75.0 million thereunder in order to replenish the remainder of working capital that was distributed to existing partners immediately prior to the IPO.

Partnership Agreement. In connection with the IPO, we executed the Third Amended and Restated Agreement of Limited Partnership (“Amended Partnership Agreement”) on October 7, 2014. The Amended Partnership Agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date, subject to certain terms and conditions.  See Note 13 for additional information.

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2.Summary of Significant Accounting Policies

Principles of Consolidation.  Our consolidated financial statements have been prepared in accordance with GAAP. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

Reclassification.  Certain previously reported amounts have been reclassified to conform to the current year presentation. For the years ended December 31, 2014 and 2013, we reclassified $9,911,000 and $1,687,000, respectively, from gathering, transportation and storage fees to crude oil sales to conform to the current year presentation.

Use of Estimates.  The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Cash and Cash Equivalents.  We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Bank overdrafts that do not meet the right of offset criteria are recorded in capital leases and short-term debt in the consolidated balance sheets.

Restricted Cash.  Restricted cash consists of cash balances that are restricted as to withdrawal or usage and at December 31, 2014, included cash to secure crude oil production taxes payable to the applicable taxing authorities.

Accounts Receivable.  Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the consolidated statements of operations. The allowance for doubtful accounts was $1,217,000 and $1,134,000 as of December 31, 2015 and 2014, respectively. Bad debt expense for the years ended December 31, 2015, 2014 and 2013 was $1,212,000,  $820,000 and $855,000, respectively.

Inventory.  Inventory is mainly comprised of crude oil, NGLs, refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. Cost of crude oil, NGLs and refined products inventory is determined using the first-in, first-out (FIFO) method. Cost of propane cylinders is determined using the weighted average method.

Prepaid Expenses and Other Current Assets.  Prepaid expenses and other current assets primarily relate to prepaid insurance premiums, which totaled $1,239,000 and $1,044,000, and insurance claim receivables, which totaled $115,000 and $965,000 as of December 31, 2015 and 2014, respectively.

Derivative Instruments and Hedging Activities.  We recognize all derivative instruments as either assets or liabilities on the balance sheet at their respective fair values. We did not have any derivatives designated in hedging relationships during the years ended December 31, 2015, 2014 and 2013. Therefore, the change in the fair value of the derivative asset or liability is reflected in net loss in the consolidated statements of operations (mark-to-market accounting). Cash flows from derivatives settled are reported as cash flow from operating activities, in the same category as the cash flows from the items being economically hedged.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sales exception (“NPNS”) accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.

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Property, Plant and Equipment.  Property, plant and equipment is recorded at historical cost of construction, or, upon acquisition, the fair value of the assets acquired. Repairs and maintenance costs are expensed as incurred. Any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the account, and any resulting gain or loss is recognized within the consolidated statements of operations.

We account for asset retirement obligations by recognizing on our balance sheet the net present value of any legally binding obligation to remove or remediate tangible long-lived assets, such as requirements to dispose of equipment. We record a liability for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:

Buildings	20	-	30	years
Leasehold improvements		Various*
Transportation equipment	5	-	15	years
Propane tanks and cylinders	3	-	25	years
Bulk storage tanks			20	years
Pipelines			20	years
Office furniture and fixtures	5	-	10	years
Other equipment	3	-	31	years

*Depreciated over the shorter of the life of the leasehold improvement or the lease term.

Leases.  We have both capital and operating leases. Classification is made at the inception of the lease. The classification of leases is based on the extent to which risks and rewards incidental to ownership of a leased asset lie with the lessor or the lessee.

Leased property meeting certain capital lease criteria is capitalized and the present value of the related lease payments is recorded as a liability. The present value of the minimum lease payments is calculated utilizing the lower of our incremental borrowing rate or the lessor’s interest rate implicit in the lease, if known by us. Depreciation of capitalized leased assets is computed utilizing the straight-line method over the shorter of the estimated useful life of the asset or the lease term and is included in depreciation and amortization in our consolidated statements of operations. However, if the lease meets the bargain purchase or transfer of ownership criteria, the asset shall be amortized in accordance with our normal depreciation policy for owned assets.

Minimum rent payments under operating leases are recognized as an expense on a straight-line basis over the lease term, including any rent free periods.

Impairment of Long-Lived Assets.  Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3). For assets held for sale, we compare the fair value of the disposal group to its carrying value. Under the assets held for sale criteria, the order of impairment is based on (i) testing other assets, such as accounts receivable, inventory and indefinite-lived intangible assets, for impairment (ii) testing goodwill for impairment and (iii) testing the long-lived asset group for impairment. In connection with the sale of our Mid-Continent Business (defined in Note 3 and classified as held for sale at December 31, 2015), we recorded an impairment charge of $4,970,000 during the year ended December 31, 2015

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related to long-lived assets, which is classified in net loss from discontinued operations in the consolidated statements of operations.

Goodwill and Other Intangible Assets.We apply Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill. In accordance with these standards, goodwill is not amortized but is tested for impairment at least annually, or more frequently whenever a triggering event or change in circumstances occurs at the reporting unit level. A reporting unit is the operating segment, or business one level below the operating segment if discrete financial information is prepared and regularly reviewed by segment management. We have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.

In 2015, we recognized impairment charges of $23,574,000 and $6,322,000 related to the goodwill in our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volume in those reporting units.  We also recorded an additional goodwill impairment charge of $7,939,000 triggered by the disposition of our Mid-Continent Business. The $7,939,000 of goodwill was allocated to the Mid-Continent Business based on the relative fair value of the Mid-Continent Business and the portion of the reporting unit that was retained by us. No provision for impairment of goodwill was recorded during 2014 or 2013.

During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the crude oil supply and logistics reporting unit, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by us. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.

Business Combinations.  When a business is acquired, we allocate the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. The accounting standard for business combinations requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs associated with the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt’s stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite. Contingent consideration obligations are recorded at fair value on the date of acquisition, with increases or decreases in the fair value arising from changes in assumptions or discount periods recorded as contingent consideration expenses in the consolidated statement of operations in subsequent periods. The fair values assigned to tangible and intangible assets acquired and liabilities assumed, including contingent consideration, are based on management’s estimates and assumptions, as well as other information compiled by management, including valuations that utilize customary valuation procedures and techniques.

When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting. Under a common control acquisition, the assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

Deferred Financing Costs.  Debt issuance costs related to our revolving credit agreement (see Note 11) are deferred and are recorded net of accumulated amortization in the consolidated balance sheets as deferred financing costs, and totaled $2,809,000 and $3,712,000 at December 31, 2015 and 2014, respectively. These costs are amortized over the terms of the related debt using the effective interest rate method for the notes payable and the straight-line method for the revolving credit facilities. As a result of the financing transactions discussed in Note 11, we wrote off $1,634,000 of

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deferred financing costs associated with the extinguishment of debt during the year ended December 31, 2014 which is recorded in loss on extinguishment of debt in the consolidated statements of operations. Amortization of deferred financing costs is recorded in interest expense and totaled $909,000,  $906,000 and $1,103,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Customer Deposits and Advances.  Certain customers are offered a prepayment program which requires a customer to pay a fixed periodic amount or to otherwise prepay a portion of their anticipated product purchases. Customer prepayments in excess of associated billings are classified as customer deposits and advances in the consolidated balance sheets.

Revenue Recognition.  We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller’s price to the buyer is fixed and determinable and collectability is reasonably assured.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the consolidated statements of operations.

Crude Oil Pipelines and Storage.  The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, we enter into sale and purchase contracts with counterparties instead of pipeline transportation agreements. In such cases, we assess the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. In addition, we also provide crude oil transportation services to third party customers.

Refined Products Terminals and Storage.  We generate fee-based revenues for terminal and storage services with longstanding customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Such fee-based revenues are recognized when services are proved upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

NGLs Distributions and Sales.  Revenues from the NGLs distributions and sales are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees.

Operating expenses.  Operating expenses primarily include personnel, vehicle, delivery, handling, office, selling, and other expenses related to the distribution, terminal and storage of products and related supplies.

Expenses associated with the delivery of products to customers (including vehicle expenses, expenses of delivery personnel and vehicle repair and maintenance) are classified as operating expenses in the consolidated statements of operations.

General and administrative expenses.  General and administrative expenses primarily include wages and benefits and department related costs for human resources, legal, finance and accounting, administrative support and supply.

Fair value measurement.  We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. We determine fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When

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considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The fair value of our derivatives (see Note 12) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The fair value of our contingent liabilities (see Note 5) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). We do not have any other assets or liabilities measured at fair value on a recurring basis.

Our other financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and long term debt. The carrying value of our trade and other receivables, accounts payable and accrued expenses approximates fair value due to their highly liquid nature, short term maturity, or competitive rates assigned to these financial instruments. The fair value of long-term debt approximates the carrying value as the underlying instruments bear interest at rates similar to current rates offered to us for debt with the same remaining maturities.

Concentration Risk.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have not experienced any losses related to these balances.

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues from transactions with an external customer amounting to 10% or more of revenue are disclosed below, together with the identity of the reportable segment.

		Year Ended December 31,
Customer	ReportableSegment	2015	2014	2013
		(inthousands)
Customer A	Crudeoil pipelines and storage, NGLs distribution and sales	252,969	164,115	*
Customer B	Crudeoil pipelines and storage, Refined products terminals and storage	*	90,923	48,544

* Revenues are less than 10% of the total revenues during the period.

We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

Income Taxes.  We are a limited partnership, and therefore not directly subject to federal income taxes or most state income taxes. Our taxable income (loss) will be included in the federal income tax returns filed by the individual partners. Accordingly, no federal income tax provision has been made in our consolidated financial statements since the income tax is an obligation of the partners. We are subject to the Texas margin tax, which is reported in income tax expense in the consolidated statements of operations.

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ASC 740, “Income Taxes”, requires the evaluation of tax positions taken or expected to be taken in the course of preparing our state tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe we have any tax positions taken within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions as part of our income tax expense, when and if they become applicable.

Equity-Based Compensation.  We account for equity based compensation by recognizing the fair value of awards on the grant date or the date of modification, as applicable, into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required.

Comprehensive Loss.  For the years ended December 31, 2015, 2014 and 2013, comprehensive loss was equal to net loss.

Recent Accounting Pronouncements.  In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 requires equity investments to be measured at fair value with changes in fair value recognized in net income; simplifies the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; requires separate presentation of financial assets and financial liabilities by measurement category and form of financial assets on the balance sheet or the accompanying notes to the financial statements and clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. This standard does not allow for early adoption except related to credit risk adjustment in other comprehensive income. The adoption of ASU 2016-01 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This ASU is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early application permitted and, upon adoption, may be applied either prospectively or retrospectively. We early adopted, retrospectively, ASU 2015-17. There is no impact from the adoption of this ASU as our deferred taxes are already presented under the non-current classification for all periods presented.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). ASU 2015-16 changes how the acquirer recognizes adjustments to the provisional amounts of a business combination that are identified during the measurement period  from a retrospective application of all affected financial periods to be recorded in the reporting period in which the adjustment amounts are determined. Additionally, the company needs to disclose, of the amounts recorded in current periods, what amounts would have been reported in previous periods if the adjustments had been recognized at the acquisition date.  ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015.  Early adoption of this ASU is permitted. The adoption of ASU 2015-16 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). ASU 2015-15 provides SEC Staff guidance to ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost, as it relates to debt issuance cost associated with line-of-credit arrangements.

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The SEC staff recognized that ASU 2015-03 did not address presentation or subsequent measurement of debt issuances cost related to line-of-credit arrangements and noted that the SEC Staff wouldn’t object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings of the line-of credit arrangement. ASU 2015-15 was adopted in the third quarter of 2015 with ASU 2015-03 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

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

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

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

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

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

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 supersedes the existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize

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revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted. We are currently evaluatingthe potential impact this standard will have on our consolidated financial statements and related disclosures.

3. Discontinued Operations

Mid-Continent. On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”) to JP Development, simultaneous with JP Development’s sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9,685,000, in cash, which included certain adjustments related to inventory and other working capital items. We expect to recognize a loss on disposal of $12,909,000 related to the Mid-Continent Business. As of December 31, 2015, the Mid-Continent Business met all the criteria to be classified as asset held for sale in accordance with ASC 360, therefore, we classified all the related assets and liabilities as held for sale in the consolidated balance sheets. In addition, we allocated $7,939,000 of goodwill to the Mid-Continent Business, which was based on the relative fair value of the disposed Mid-Continent Business and the portion of the crude oil supply and logistics reporting unit that was retained by us. The $7,939,000 was subsequently impaired and contributed to the overall net loss from discontinued operations. The operating results of the Mid-Continent Business have been classified as discontinued operations for all periods presented in the consolidated statements of operations. We combined the cash flows from the Mid-Continent Business with the cash flows from continuing operations for all periods presented in the consolidated statements of cash flows. The Mid-Continent Business will not generate any continuing cash flows subsequent to the date of disposition. Prior to the classification as discontinued operations, we reported the Mid-Continent Business in our crude oil pipelines and storage segment. The following table summarizes selected financial information related to the Mid-Continent Business’ operations in the years ended December 31, 2015, 2014 and 2013.

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Consolidated Statements of Operations

The discontinued operations of the Mid-Continent Business are summarized below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands, except unit and per unit data)
REVENUES
Crude oil sales	$	429,716	$	967,359	$	1,711,036
Gathering, transportation and storage fees		16		31		204
Other revenues		52		90		124
Total revenues		429,784		967,480		1,711,364
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		426,886		961,428		1,687,827
Operating expense		1,402		1,930		4,197
General and administrative		867		936		996
Impairment of goodwill and assets held for sale		12,909		—		—
Depreciation and amortization		2,281		2,258		2,358
Loss on disposal of assets, net		119		229		—
Total costs and expenses		444,464		966,781		1,695,378
OPERATING INCOME (LOSS)		(14,680)		699		15,986
OTHER INCOME (EXPENSE)
Interest expense		(296)		(412)		(830)
Loss on extinguishment of debt		—		—		—
Other income, net		25		46		1
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES		(14,951)		333		15,157
Income tax (expense) benefit		—		—		—
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	(14,951)	$	333	$	15,157

Consolidated Balance Sheets

The current and non-current assets and liabilities of the Mid-Continent Business are as follows:

	December 31,		December 31,
	2015		2014
	(in thousands)
ASSETS
Current assets
Inventory	$	2,692	$	15,149
Prepaid expenses and other current assets		38		—
Total Current assets of discontinued operations held for sale		2,730		15,149
Non-current assets
Property, plant and equipment, net		5,203		10,458
Goodwill		—		7,939
Intangible assets, net		1,138		2,981
Deferred financing costs and other assets, net		303		343
Total Non-current assets of discontinued operations held for sale		6,644		21,721
Total Assets of discontinued operations held for sale	$	9,374	$	36,870
LIABILITIES
Current liabilities
Accrued liabilities	$	640	$	—
Total Current liabilities of discontinued operations held for sale	$	640	$	—

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The following table summarizes other selected financial information related to the Mid-Continent Business.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Depreciation	$	1,127	$	1,104	$	1,204
Amortization		1,154		1,154		1,154
Capital expenditures		637		316		1,327
Other operating noncash items related to discontinued operations:
Impairment on goodwill and assets held for sale	$	12,909	$	—	$	—
Derivative valuation changes		630		—		—
Loss on disposal of assets		119		229		—
Non-cash inventory LCM adjustments		—		222		—
Investing noncash items related to discontinued operations:
Accrued capital expenditures	$	—	$	218	$	—

Bakken Business. On June 30, 2014, we (“Seller”) entered into and simultaneously closed an Asset Purchase Agreement with Gold Spur Trucking, LLC (“Buyer”), pursuant to which the Seller sold all the trucking and related assets and activities in North Dakota, Montana and Wyoming (the “Bakken Business”) to the Buyer for a purchase price of $9,100,000. As a result, we recognized a loss on this sale of approximately $7,288,000 during the second quarter of 2014, which primarily relates to the write-off of a customer contract associated with the Bakken Business. In addition, immediately prior to the sale, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that was retained by us. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.

The Bakken Business operations have been classified as discontinued operations for all periods in the consolidated statements of operations. We combined the cash flows from the Bakken Business with the cash flows from continuing operations for all periods presented in the consolidated statements of cash flows. The Bakken Business will not generate any continuing cash flows subsequent to the date of disposition. Prior to the classification as discontinued operations, we reported the Bakken Business in our crude oil pipelines and storage segment. The following table summarizes selected financial information related to the Bakken Business’s operations in the years ended December 31,  2014 and 2013.

		Year Ended December 31,
		2014		2013
	(in thousands)
Revenues from discontinued operations	$	7,865	$	19,283
Net loss of discontinued operations, including loss on disposal of $7,288 in 2014		(9,608)		(1,182)

4. Net Loss Per Unit

Net loss per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO by the weighted-average number of common units and subordinated units outstanding for the period. Loss per limited partner unit is calculated in accordance with the two-class method for determining loss per unit for master limited partnerships (“MLPs”) when incentive distribution rights (“IDRs”) and other participating securities are present. The two-class method requires that loss per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. For the years ended December 31, 2015 and 2014, dilutive loss per unit was equal to basic loss per unit because all instruments were antidilutive.

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On January 26, 2016, the Board of Directors of our general partner declared a cash distribution for the fourth quarter of 2015 of $0.325 per common unit and subordinated unit.  The distribution was paid on February 12, 2016 to unitholders of record as of February 5, 2016.

	Year ended December 31, 2015
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	24,172	$	23,571	$	47,743
Distributions in excess of net income		(46,002)		(45,446)		(91,448)
Net loss from continuing operations attributable to the limited partners	$	(21,830)	$	(21,875)	$	(43,705)
Net loss from discontinued operations attributable to the limited partners		(7,521)		(7,430)		(14,951)
Net loss attributable to the limited partners	$	(29,351)	$	(29,305)	$	(58,656)
Weighted average units outstanding:
Basic		18,373,594		18,151,700		36,525,294
Net loss per unit:
Basic and diluted from continuing operations	$	(1.19)	$	(1.20)
Basic and diluted from discontinued operations	$	(0.41)	$	(0.41)
Basic and diluted total	$	(1.60)	$	(1.61)

	Year ended December 31, 2014
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	5,523	$	5,491	$	11,014
Distributions in excess of net income		(14,983)		(14,981)		(29,964)
Net loss from continuing operations attributable to the limited partners	$	(9,460)	$	(9,490)	$	(18,950)
Net income from discontinued operations attributable to the limited partners		167		167		334
Net loss attributable to the limited partners	$	(9,293)	$	(9,323)	$	(18,616)
Weighted average units outstanding:
Basic		18,212,632		18,209,948		36,422,580
Net income (loss) per unit:
Basic and diluted from continuing operations	$	(0.52)	$	(0.52)
Basic and diluted from discontinued operations	$	0.01	$	0.01
Basic and diluted total	$	(0.51)	$	(0.51)

The following data shows securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the year ended December 31, 2015:

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Phantom units 406,218

5. Acquisitions and Dispositions

2015 Acquisitions

Acquisition of Southern Propane Inc. On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company. The acquisition expanded the asset base and market share of our NGL distribution and sales segment, specifically the acceleration of our entry into the Houston, Texas market, as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16,292,000 consisted of a $12,475,000 cash payment that was paid on the acquisition date, and which was funded through the use of borrowings from our revolving credit facility, a $108,000 cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3,442,000 and a contingent earn-out liability with a value of $267,000 that is subject to the achievement of certain gross profit targets at Southern.  The earn-out period covers the period from June 2015 through December 2016, and the maximum earn-out that could be earned is $1,250,000. The common units issued with this acquisition were issued in a private offering conducted in accordance with the exemption from the registration requirements of Section 4(a)(2) of the Securities Act of 1933, as amended, as such units were issued to the owners of a business acquired in a privately negotiated transaction not involving any public offering or solicitation.

The fair value of the contingent earn-out liability was estimated by applying an expected present value technique based on the probability-weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The contingent earn-out was established at the time of the acquisition and is revalued at each reporting period. Based on the actual post-acquisition performance results and revised projections, we decreased the fair value of the Southern contingent earn-out liability to $243,000 as of December 31, 2015, which is recorded in Other long-term liabilities in the consolidated balance sheets. For the year ended December 31, 2015, we recognized $24,000 in income related to the changes in the fair value of the contingent earn-out liability which is included in Other income, net, in our consolidated statements of operations. 

The following table represents our allocation of the total purchase price of this acquisition to the assets acquired (in thousands):

Accounts receivable	$	932
Inventory		24
Total current assets		956
Property, plant and equipment		2,962
Intangible assets:
Customer relationships		6,163
Noncompete agreements		292
Trade names		113
Total identifiable net assets acquired		10,486
Goodwill		5,806
Net assets acquired	$	16,292

Goodwill associated with the Southern acquisition principally results from synergies expected from integrated operations. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names are amortized over an estimated useful life of one year, customer relationships are amortized over a

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weighted average useful life of 12 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.

Revenues attributable to Southern included in the consolidated statements of operations totaled $3,849,000 for the period from May 8, 2015 to December 31, 2015. We do not account for the operations of Southern on a stand-alone basis, therefore, it is impracticable to report the amounts of net income of Southern included in the consolidated statements of operations related to the post-acquisition periods.

2013 Acquisitions

The following acquisitions by JP Development were acquired by us in the Common Control Acquisition.

Acquisition of Wildcat Permian Services LLC.  On October 7, 2013, JP Development acquired all of the issued and outstanding equity interests of Wildcat Permian for a total consideration of $212,804,000 in cash. Wildcat Permian owns and operates a long-term contracted oil pipeline system in Crockett and Reagan Counties, Texas. On February 12, 2014, we acquired Wildcat Permian from JP Development as part of the Dropdown Assets as described in Note 1.

The acquisition extended our reach into the core of the rapidly developing Midland Basin, which further diversified our portfolio of transportation and storage assets.

The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed on October 7, 2013 (in thousands):

Cash	$	2,570
Accounts receivable		16,068
Inventory		283
Short-term prepaid asset		134
Total current assets		19,055
Property, plant and equipment		33,962
Long-term prepaid asset		951
Intangible assets:
Customer relationships		67,700
Total assets acquired		121,668
Total liabilities assumed		(17,227)
Total identifiable net assets acquired		104,441
Goodwill		108,363
Net assets acquired	$	212,804

Goodwill associated with the Wildcat Permian acquisition principally results from expected future growth potential as well as the synergies expected from integrations with our other crude oil business. We allocated $11,242,000 of the goodwill associated with the Wildcat Permian acquisition to our crude oil supply and logistics reporting unit. The fair value of the acquired intangible asset was estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 17 years.

Revenues attributable to Wildcat Permian and included in the consolidated statements of operations totaled $70,580,000, $64,136,000 and $10,878,000 for the years ended December 31, 2015, and 2014, and the period from October 7, 2013 to December 31, 2013, respectively. We do not account for the operations of Wildcat Permian on a stand-alone basis, therefore, it is impracticable to report the amounts of earnings of Wildcat Permian included in the consolidated results of operations related to the post acquisition periods.

Other 2013 Acquisitions.In addition to the acquisition described above, in 2013, JP Development also acquired the businesses in the table noted below for a total purchase price of $27,048,000. The total consideration consisted of $23,085,000 paid in cash, JP Development’s investment in our Class C Common Units representing limited

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partner interests valued at $1,628,000, a contingent earn-out with a fair value of $1,280,000 that was subject to the achievement of certain trucking revenue goals at Alexander Oil Field Service, Inc. (“AOFS”), and a contingent earn-out with a fair value of $1,055,000 that is subject to the achievement of certain trucking revenue goals at Highway Pipeline, Inc. (“HPI”). The AOFS earn-out period covers the period from September 1, 2013 to August 31, 2015, and the maximum earn-out which could be earned was $1,628,000 over the course of two years. The HPI earn-out period covers the period from January 1, 2014 to December 31, 2016, and the maximum earn-out that could be earned is $3,000,000 over the course of three years.

The fair value measure of the contingent earn-outs was estimated by applying an expected present value technique based on the probability- weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The contingent earn-outs were established at the time of the acquisitions and are revalued at each reporting period. We estimated the fair value of the AOFS contingent earn-out liability to be $790,000 as of December 31, 2014. In the third quarter of 2015, we paid $488,000 as a settlement of the AOFS contingent earn-out. As of December 31, 2014, the fair value of the HPI contingent earn-out liability was $1,367,000. We decreased the fair value of the HPI contingent earn-out liability to $234,000 as of December 31, 2015, based on the actual post-acquisition performance results of the business as well as our revised expectation of the probable or possible future outcome.  As of December 31, 2015, the HPI liability is recorded in Other-long term liabilities in the consolidated balance sheets. For the years ended December 31, 2015 and 2014, we recognized income of $1,435,000 and losses of $435,000, respectively, related to the changes in fair value of the AOFS and HPI liabilities, which is included in Other income, net, in our consolidated statements of operations.

Dateof acquisition	Name of acquired entity	Totalpurchaseprice
		(inthousands)
July 15, 2013	BMHPropane, LLC (d/b/a Valley Gas)	$	2,437
August 30, 2013	Alexander Oil Field Service, Inc.		7,792
October 11, 2013	Highway Pipeline, Inc.		16,819

On February 12, 2014, we acquired the above businesses from JP Development in the Common Control Acquisition described in Note 1.

The following table represents the allocation of the aggregated purchase price to the assets acquired related to the three acquisitions described above, which are individually insignificant at their respective original acquisition dates by JP Development (in thousands):

Accounts receivable	$	504
Inventory		15
Total current assets		519
Property, plant and equipment		8,503
Intangible assets:
Trade names and trademarks		286
Customer relationships		8,022
Noncompete agreements		429
Total assets acquired		17,759
Total liabilities assumed		(475)
Total identifiable net assets acquired		17,284
Goodwill		9,764
Net assets acquired	$	27,048

The goodwill amounts noted for all 2013 acquisitions reflect the difference between purchase prices less the fair value of net assets acquired. Goodwill associated with these acquisitions principally results from synergies expected from integrated operations and from assembled workforce. We do not believe that the acquired intangible assets have an

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significant residual value at the end of their respective useful lives. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names and trademarks are amortized over an estimated useful life of 2 years, customer relationships are amortized over a weighted average useful life of 6 years, and non-compete agreements are amortized over an estimated useful life of 3 years.

Revenues attributable to the three acquisitions above and included in the consolidated statements of operations totaled $14,008,000, $18,329,000 and $5,781,000, for the years ended December 31, 2015, 2014 and the period from each respective acquisition date to December 31, 2013, respectively. We do not account for the operations of  these acquisitions on a stand-alone basis, therefore, it is impracticable to report the amounts of earnings of these acquisitons included in the consolidated results of operations related to the post acquisition periods.

Pro Forma Information

The following unaudited pro forma information summarizes the results of operations for the year ended December 31, 2013 as if the significant acquisition of JP Permian (effectively acquired by us on October 7, 2013—see Note 1) had been completed at the beginning of the year. Financial information of certain acquisitions was impractical to obtain and accordingly have not been included in the proforma financial information presented below.

The pro forma data combines our consolidated results with those of JP Permian (prior to acquisition) for the period shown. The results are adjusted for amortization, depreciation, interest expense and income taxes relating to the acquisition. No effect has been given to cost reductions or operating synergies in this presentation. These pro forma amounts do not purport to be indicative of the results that would have actually been achieved if the acquisitions had occurred as of the beginning of the period presented or that may be achieved in the future. The pro forma amounts are as follows:

	Year ended December 31, 2013
	(inthousands)
	(unaudited)
Pro forma consolidated revenue from continuing operations	$	393,837
Pro forma consolidated net loss from continuing operations	$	(32,501)

Disposition of crude oil supply and logistics assets. On September 30, 2015, we entered into an asset purchase agreement pursuant to which we sold certain crude oil supply and logistics assets for a sales price of $1,914,000. We closed the transaction on November 2, 2015 and recognized a gain on disposal of $1,046,000.

6. Inventory

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

	December 31,
	2015		2014
	(in thousands)
Crude Oil	$	338	$	162
NGLs		2,364		3,342
Refined Products		430		445
Materials, supplies and equipment		1,654		1,728
Total inventory	$	4,786	$	5,677

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7. Property, Plant and Equipment, net

Property, plant and equipment, net consists of the following as of December 31, 2015 and 2014:

	December 31,
	2015		2014
	(in thousands)
Land	$	6,874	$	6,874
Buildings and improvements		12,561		12,045
Transportation equipment		46,582		39,388
Storage and propane tanks		151,988		139,721
Pipelines and linefill		77,295		54,059
Office furniture and fixtures		9,701		8,245
Other equipment		48,171		25,892
Construction-in-progress		12,763		15,175
Total property, plant and equipment		365,935		301,399
Less: accumulated depreciation		(74,481)		(49,709)
Property, plant and equipment, net	$	291,454	$	251,690

Depreciation expense totaled $29,391,000, $23,514,000 and $18,779,000 for the years ended December 31, 2015, 2014 and 2013, respectively, which is included in depreciation and amortization expense in the consolidated statements of operations. Depreciation expense amounts have been adjusted by $1,127,000,  $1,685,000 and $2,348,000 for the years ended December 31, 2015, 2014 and 2013, respectively, to present the Mid-Continent and Bakken Business’s operations as discontinued operations.

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8. Goodwill and Intangible Assets

Intangible assets consist of the following for the years ended December 31, 2015 and 2014:

	December 31, 2015
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
		(in thousands)
Customer relationships	$	82,630	$	(20,761)	$	61,869
Noncompete agreements		3,575		(2,664)		911
Trade names		553		(139)		414
Customer contract		95,594		(24,538)		71,056
Other		198		(16)		182
Total	$	182,550	$	(48,118)	$	134,432
	December 31, 2014
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
	(in thousands)
Customer relationships	$	76,466	$	(14,275)	$	62,191
Noncompete agreements		3,728		(2,283)		1,445
Trade names		2,147		(583)		1,564
Customer contract		95,594		(15,662)		79,932
Other		209		(11)		198
Total	$	178,144	$	(32,814)	$	145,330

In connection with the sale of the Mid-Continent Business, which was classified as held for sale at December 31, 2015, we recorded an impairment charge of $689,000 related to customer relationships during the year ended December 31, 2015, which is classified in net loss from discontinued operations in the consolidated statements of operations.  In addition, as a result of the sale of the Bakken Business, we wrote-off $8,060,000 in customer contracts during the year ended December 31, 2014 (see Note 3).

Amortization expense totaled $17,461,000,  $16,716,000 and $12,208,000 for December 31, 2015, 2014 and 2013, respectively, which is included in depreciation and amortization expense in the consolidatedstatements of operations.  Amortization expense amounts have been adjusted by $1,154,000,  $2,007,000 and $2,860,000 for the years ended December 31, 2015, 2014 and 2013, respectively, to present the Mid-Continent and Bakken Business’s operations as discontinued operations.

We amortize intangible assets over their estimated benefit period on a straight-line basis.

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The estimated future amortization expense for amortizable intangible assets to be recognized is as follows (in thousands):

2016	$	16,163
2017		15,754
2018		15,484
2019		13,499
2020		10,790
Thereafter		62,742
Total	$	134,432

Goodwill activity in 2014 and 2015 consists of the following:

			Refined
	Crude oil		products		NGL
	pipelines and		terminals and		distribution
	storage		storage		and sales		Total
	(in thousands)
Balance at January 1, 2014	$	150,268	$	61,163	$	31,335	$	242,766
Disposals		(1,984)		—		—		(1,984)
Balance at December 31, 2014		148,284		61,163		31,335		240,782
Goodwill acquired during the year		—		—		5,806		5,806
Goodwill impairment		(23,574)		—		(6,322)		(29,896)
Balance at December 31, 2015	$	124,710	$	61,163	$	30,819	$	216,692

We recorded a goodwill impairment charge of $29,896,000 during the year ended December 31, 2015 related to our Crude Oil Supply and Logistics and JP Liquids reporting units. Additionally, in connection with the sale of the Mid-Continent Business, we recorded a goodwill impairment charge of $7,939,000 during the year ended December 31, 2015 which is classified in net loss from discontinuing operations in the consolidated statements of operations.

During the year ended December 31, 2014, we recorded a decrease in goodwill of $1,984,000 related to the sale of the Bakken Business.

9.Accrued Liabilities

Accrued liabilities are comprised of the following as of December 31, 2015 and 2014:

	December 31,
	2015		2014
	(inthousands)
Taxes payable	$	1,204	$	1,915
Accrued payroll and employee benefits		4,756		8,148
Accrued professional fees		696		462
Royalties payable		4,163		4,281
Short-term derivative liabilities		358		10,157
Other		4,083		4,008
Total accrued liabilities	$	15,260	$	28,971

10. Capital Leases and Other Short-Term Debt

Capital Leases. We have certain leases for buildings, transportation equipment and office equipment, which are accounted for as capital leases. The leases mature between 2016 and 2021. Assets under capital lease are recorded

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within property, plant and equipment, net in the consolidated balance sheets. The following is a summary of assets held under such agreements.

	December 31,
	2015		2014
	(inthousands)
Buildings and improvements	$	16	$	138
Transportation equipment		167		261
Office furniture and equipment		133		129
Other equipment		35		49
		351		577
Less: Accumulated depreciation		(197)		(254)
Assets under capital lease, net	$	154	$	323

Scheduled repayments of capital lease obligations are as follows (in thousands):

Years ending December 31,
2016	$	153
2017		116
2018		40
2019		31
2020		22
Thereafter		11
		373
Less: amounts representing interest		(137)
Total obligations under capital leases		236
Less: current portion		(107)
Long-term capital lease obligation	$	129

The long term capital lease obligation is included within other long-term liabilities in the consolidated balance sheets.

Other Short-Term Debt. In addition, we had $91,000 bank overdrafts outstanding as of December 31, 2014.

We financed a portion of our annual insurance premium in 2013. During the year ended December 31, 2014, we repaid the outstanding balance under this arrangement of $49,000. We no longer finance our insurance premiums.

11. Long-Term Debt

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

	December 31,
	2015		2014
	(in thousands)
Bank of America revolving loan	$	162,000	$	83,000
HBH note payable		1,077		1,277
Non-compete notes payable		117		231
Total long-term debt	$	163,194	$	84,508
Less: Current maturities		(454)		(383)
Total long-term debt, net of current maturities	$	162,740	$	84,125

Bank of America Credit Agreement. On February 12, 2014, we entered into a credit agreement with Bank of America, N.A. (the “BOA Credit Agreement”), which is available for refinancing and repayment of certain existing

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indebtedness, working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions, not in contravention of law of the loan documents and to pay off our existing WFB commitments and F&M Loans (as described below). The BOA Credit Agreement consists of a $275,000,000 revolving loan, which includes a sub-limit of up to $100,000,000 for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275,000,000 up to $425,000,000, subject to obtaining additional or increased lender commitments. The BOA Credit Agreement will mature on February 12, 2019. Our obligations under the BOA Credit Agreement are collateralized by substantially all of our assets.

Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable rate. The applicable rate is (a) 1.25% for prime rate borrowings and 2.25% for LIBOR borrowings. The commitment fee is subject to an adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement and (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.

As of December 31, 2015, the unused balance of the BOA Credit Agreement was $86,870,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $26,130,000 at December 31, 2015. We are required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement and (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.

The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:

Prior to the IPO

Maintenance of certain financial covenants including a consolidated total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes (which will be increased to 4.75 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated total leverage ratio of not more than 4.75 to 1.00 from and after the issuance of certain unsecured notes, a consolidated senior secured leverage ratio of not more than 3.00 to 1.00 from and after the issuance of certain unsecured notes, a consolidated working capital (as defined in the BOA Credit Agreement) of not less than $15,000,000 and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.

Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.

After the IPO

Maintenance of certain financial covenants including a consolidated net total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 5.00 to 1.00 from and after the issuance of certain unsecured notes, a consolidated senior secured net leverage ratio of not more than 3:50 to 1:00 from and after the issuance of certain unsecured notes, available liquidity (as defined in the BOA Credit Agreement) of not less than $25,000,000 and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.

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Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.

Beginning in March 2015, we were inadvertently not in full compliance with previously existing restrictions under our revolving credit facility due to our engaging in certain financial swap contracts with a lender in our revolving credit facility. Such noncompliance was waived pursuant to Amendment No. 4. The financial swap contracts were executed as a part of our normal course hedging practices in compliance with our risk management policy and are now permitted under the terms of Amendment No. 4.Prior to February 23, 2016, our revolving credit facility contained a covenant requiring our consolidated working capital, as defined in the credit agreement, to be not less than $15,000,000. We were not in compliance with the consolidated working capital covenant as of December 31, 2015, which noncompliance was waived and which covenant was removed and the available liquidity covenant was added pursuant to Amendment No. 5.

HBH Note Payable.  We issued a $2,012,500 non-interest bearing promissory note in conjunction with the acquisition of HBH on November 15, 2011. The carrying value of this note is $1,077,000 and $1,277,000 as of December 31, 2015 and December 31, 2014, respectively, which is based on an interest rate of 5.0%. This balance is payable every January and July through December 31, 2016 based on the number of meter connections above a threshold. The minimum amount due is $2,012,500. The final remaining balance on this loan is due in full on December 31, 2016. Accretion expense, included as a component of interest expense, totaled $55,000,  $66,000 and $69,000 for the 2015, 2014 and 2013, respectively. The fair value measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs.

Non-Compete Notes Payable.  As part of the acquisition of Heritage Propane Express, LLC (“HPX”) in June 2012, we acquired several promissory notes, which were issued prior to acquisition by HPX as consideration for several non-compete agreements unrelated to the acquisition transaction. Each of the agreements has a five year term and is non-interest bearing. The fair value of the agreements is $117,000 and $231,000 at December 31, 2015 and December 31, 2014, respectively, which is based on an effective imputed interest rate of 3.5%.

Wells Fargo Credit Agreement. We had a $20,000,000 working capital revolving credit facility and a $180,000,000 acquisition revolving credit facility with Wells Fargo Bank, N.A. (the “WFB Credit Agreement”). Our outstanding borrowings under the WFB Credit Agreement were collateralized by substantially all of our assets.

On February 12, 2014, we entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement. As a result of the termination of the WFB Credit Agreement, we wrote off $1,634,000 of deferred financing costs during the year ended December 31, 2014.

F&M Bank & Trust Company Credit Agreement. On July 20, 2012, we entered into an amended and restated credit agreement with F&M Bank & Trust Company for the purchase of new, and the refinancing of existing, vehicles and equipment. The F&M Bank Credit Agreement consisted of several term loans (collectively, “F&M Loans”). Our obligations under the F&M Loans were collateralized by our vehicles and equipment financed by these loans.

On February 12, 2014, the outstanding balance on the F&M Loans of $4,135,000 was paid in full with the proceeds from the BOA Credit Agreement.

Reynolds Note Payable.  We issued a $645,000 non-interest bearing promissory note as partial consideration for the acquisition of Reynolds Brother Propane on May 1, 2012. The note was payable in two installments of $295,000 and $350,000 at the first and second anniversary of the acquisition closing date (i.e. May 1, 2013 and May 1, 2014), respectively. On May 1, 2014, we repaid the promissory note in full.

Related Party Note Payable. On November 5, 2013, we issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. On March 20, 2014, we repaid the promissory note in full.

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Scheduled principal repayments of long-term debt for each of the next five years ending December 31 and thereafter are as follows (in thousands):

2016	$	454
2017		740
2018		—
2019		162,000
2020		—
Thereafter		—
Total	$	163,194

12. Derivative Instruments

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

Commodity Price Risk. Our normal business activities expose us to risks associated with changes in the market price of crude oil and propane, among other commodities. Management believes it is prudent to limit our exposure to these risks, which include our (i) propane purchases, (ii) pre-existing or anticipated physical crude oil sales and (iii) certain crude oil held in inventory.  To meet this objective, we use a combination of fixed price swap and forward contracts. At times, we may also terminate or unwind hedges or portions of hedges in order to meet cash flow objectives or when the expected future volumes do not support the level of hedges. Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered.  While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. 

In the first quarter of 2015, we entered into several long-term fixed price forward sale contracts related to certain barrels of crude oil we had on hand as of December 31, 2014, effectively locking these barrels at higher future sales prices in future periods.  These forward sale contracts are intended to mitigate the effect of the decline in crude oil prices, but do not qualify for NPNS accounting under GAAP, because we normally buy and sell crude oil inventory either within the same month or in the following month. As a result, these longer than normal term forward sale contracts were given mark-to-market accounting treatment. As these forward sale contracts relate to the marketing assets in our Mid-Continent Business (see Note 3), the fair values of the forward contracts have been classified as held for sale in the consolidated balance sheets.  As of December 31, 2015, the fair value of the Mid-Continent forward contracts is $630,000 and is included in current liabilities of discontinued operations held for sale in the consolidated balance sheets.

  In August 2015, we paid approximately $8,745,000 to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the NPNS exception as of December 31, 2015 and 2014, none of which were designated as hedges for accounting purposes.

F-31

	December 31, 2015		December 31, 2014
	NotionalVolume	Maturity	Notional Volume	Maturity
Fixed Price Swaps :
Propane (Gallons)	8,614,631	Jan 2016 - July 2017	27,958,302	Jan 2015 - Dec 2016
Crude Oil (Barrels)	(93,000)	Jan 2016	—	—

Interest Rate Risk. We are exposed to variable interest rate risk as a result of variable-rate borrowings under our revolving credit facilities. We entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of our debt with a variable-rate component. These swaps changed the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, we received variable interest rate payments and made fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that was swapped.  As of December 31, 2014, our outstanding interest rate swap contracts contained a notional amount of $75,000,000.  Our interest rate swap agreements expired in July and September 2015.

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

Fair Value of Derivative Instruments. We measure derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize indirectly observable (“level 2”) inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of our derivative contracts are designated as hedging instruments. The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets as of December 31, 2015 and 2014.

		Asset Derivatives				Liability Derivatives
		December 31,		December 31,		December 31,		December 31,
	Balance Sheet Location	2015		2014		2015		2014
		(in thousands)
Commodity swaps	Prepaid expenses and other current assets	$	92	$	—	$	—	$	—
Commodity swaps	Accrued liabilities		—		—		(450)		(8,941)
Commodity swaps	Other long-term liabilities		—		—		(24)		(3,251)
Interest rate swaps	Accrued Liabilities		—		—		—		(158)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the consolidated balance sheet as of December 31, 2015 that are subject to enforceable master netting arrangements.

	As of December 31, 2015
	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented in the Balance Sheet		Financial Collateral		Net Amount
	(in thousands)
Derivative Assets:
Derivative contracts - current	$	92	$	(92)	$	—	$	—	$	—
Derivative contracts - noncurrent		—		—		—		—		—
Derivative Liabilities:
Derivative contracts - current	$	450	$	(92)	$	358	$	—	$	358
Derivative contracts - noncurrent		24		—		24		—		24

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

The following tables summarize the amounts recognized with respect to our derivative instruments within the consolidated statements of operations.

	Location of Gain (Loss) Recognized in	Amount of Gain/(Loss) Recognized in Income on Derivatives
	Income on Derivatives	December 31, 2015		December 31, 2014		December 31, 2013
		(in thousands)
Commodity derivatives (swaps)	Cost of sales		(3,056)		(13,762)		902
Interest rate swaps	Interest expense		(27)		(227)		(168)

For the year ended December 31, 2015, we recognized $1,962,000 in total losses with respect to derivative instruments related to the Mid-Continent business which have been included in amounts classified as discontinued operations in the consolidated statements of operations.

In the consolidated statements of cash flows, the effects of settlements of derivative instruments are classified as operating activities, consistent with the related transactions.

13. Partners’ Capital

Initial Public Offering.  On October 7, 2014, we closed on our IPO of 13,750,000 common units, representing a 37.7% interest in us. Total proceeds from the sale of the units were $257.1 million, net of underwriting discounts and structuring fees. See Note 1 for details of the IPO and recapitalization transactions.

Preferred Units. On August 1, 2013, we converted all 524,746 of the then-outstanding Series A Convertible Preferred Units, all 552,348 of the then-outstanding Series B Convertible Preferred Units, and all 59,270 of the then-outstanding Series C Convertible Preferred Units previously issued to Lonestar, on a one-for-one basis into Class A Common Units.

On March 28, 2014, we authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the “Series D Preferred Units”) for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the “Subscription Agreement”) by and among us, JP Energy GP II LLC, a Delaware limited liability company and general partner to the Partnership (the “General Partner”) and Lonestar. This transaction resulted in proceeds to us of  $40,000,000. During the year ended December 31, 2014, we issued to Lonestar 110,727 Series D PIK Units related to the distributions earned for the three months ended June 30, 2014 and the three months ended September 30, 2014. On October 7, 2014, we paid $42,436,000 from proceeds related to the IPO to redeem all then outstanding Series D Preferred Units.

Common Units. Throughout 2013, we issued an aggregate of 88,114 Class C Common Units to JP Development for total net proceeds of $3,128,000.

On February 12, 2014, we issued 363,636 Class A Common Units to Lonestar for total net proceeds of $8,000,000.

With the exception of the distribution of proceeds upon a “Change of Control Event” as described in the Partnership Agreement, all Class A Common Units, Class B Common Units, and Class C Common Units (collectively, the “Existing Common Units”) had the same terms and conditions.

Prior to the closing of the IPO, the Existing Common Units were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units. An aggregate of 18,213,502 of the Existing

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Common Units held by existing partners were automatically converted into 18,213,502 subordinated units. Subsequent to the closing of our IPO, the remaining 4,463,502 Existing Common Units were automatically converted into common units on a one-to-on basis and we issued 13,750,000 common units to the public.

On May 8, 2015, in connection with the Southern acquisition, we issued 266,951 common units valued at $3,442,000.

Subordinated Units. Our Amended Partnership Agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash, defined below, each quarter in an amount equal to $0.3250 per common unit, which amount is defined in our Amended Partnership Agreement as the minimum quarterly distribution (“MQD”), plus any arrearages in the payment of the MQD on the common units from prior quarters, before any distributions of available cash may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the MQD plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution milestones described in the Amended Partnership Agreement have been met.

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

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

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

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

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

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

General Partner Interest and IDRs. As of December 31, 2013,the General Partner had 45 general partner units. On October 7, 2014, subsequent to the closing of the IPO, the 45 general partner units were recharacterized as a non-economic general partners interest in us.

The non-economic general partner interest in us does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us, and will be entitled to receive distributions on such interests.

Incentive distribution rights represent the right to receive an increasing percentage (15.0%,  25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our Amended Partnership Agreement.

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The following discussion assumes that there are no arrearages on the common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

first,  100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.37375 per unit for that quarter (the "first target distribution");

second,  85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.40625 per unit for that quarter (the "second target distribution");

third,  75.0% to all unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.4875 per unit for that quarter (the “third target distribution”); and

thereafter,  50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).

Distributions. Prior to our IPO, our Partnership Agreement required that, within 60 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 the General Partner. In connection with the IPO, we entered into the Amended Partnership Agreement, which requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date, subject to certain terms and conditions. During the year ended December 31, 2014, we did not make any cash distributions.  During the years ended December 31, 2015 and 2013, we made the following cash distributions per unit:

	Cash Distribution
Distribution Date	(per unit)
February 2013	$	0.5000
July 2013		0.5000
August 2013		0.5000
February 2015		0.3038	(1)
May 2015		0.3250
August 2015		0.3250
November 2015		0.3250

(1) Represents a prorated amount of our minimum quarterly distribution of$0.325per common unit, based on the number of days between the closing of the IPO on October 7, 2014 and December 31, 2014.

We paid a cash distribution of $0.325 per common unit and subordinate unit on February 12, 2016.

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Valuation of Units.  Prior to our IPO, fair value of the Class B and Class C common units was estimated based on enterprise value calculated using the discounted cash flow method (Level 3). Material unobservable inputs used to estimate the fair value include weighted average cost of capital (“WACC”) and market multiple used in calculating the terminal value.  The following table presents the inputs used on each major valuation date during 2013:

	December 31, 2013					April 19, 2013
WACC	10.71	%	-	11.21	%	9.41	%	-	9.91	%
Market multiple	12.05		-	12.55	times	10.5		-	11	times

14. Unit-Based Compensation

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

The following table presents phantom units activity for the year ended December 31, 2015:

Phantom Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—	$	—
Service condition grants	497,479		12.84
Vested service condition	(8,250)		12.90
Forfeited service condition	(96,809)		12.26
Outstanding at the end of period	392,420		12.99

Total unit-based compensation expense related to our phantom units was $849,000 for the year ended December 31, 2015 which was recorded in general and administrative expense in the consolidated statement of operations.

We expect to recognize $2.5 million of compensation expense related to non-vested phantom units over a weighted average period of 1.6 years. We have estimated a weighted average forfeiture rate of 41% in calculating the unit-based compensation expense.

Restricted (Non-Vested) Common and Subordinated Units.  Prior to the completion of our IPO on October 7, 2014, from time to time, we granted service condition restricted class B common units to certain key employees. Such service condition restricted common units require the recipients’ continuous employment with us and vest, according to the vesting schedule in each respective grant agreement, over certain periods, typically three to five years.

Pursuant to certain employment agreements, as amended, between us and certain employees, we were obligated to grant restricted Class B common units to those employees upon their achievement of certain agreed-upon performance goals that were measured by different milestones. Different milestone achievements caused different amounts of restricted Class B common units to be awarded. The maximum amount of the restricted Class B common units that could have been issued pursuant to these employment agreements, as amended, was 100,000 units. Prior to year ended December 31, 2013, 75,000 restricted Class B common units were issued as a result of the employees’ achievement of certain milestones and the unit-based compensation expense related to these units have been fully recorded as general

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and administrative expenses in respective historical periods.  With respect to the remaining 25,000 restricted Class B common units to be issued, we estimated the probable number of years for the performance goals to be achieved and have recognized the related unit-based compensation expense over the estimated number of years.  During the second quarter of 2015, each employee terminated their employment with us prior to one employee achieving their performance goal related to the remaining 25,000 restricted Class B common units.  As a result, we reversed previously recognized unit-based compensation expense of $297,000.  

Fair value of the restricted class B common units equaled the fair value of our common unit at the respective grant dates. We estimate the fair value of our common unit by dividing the estimated total equity value by the number of outstanding units. Estimated total equity value was determined using the income approach of discounting the estimated future cash flow to its present value.

Immediately prior to the IPO, each of our Class B common unit was split into approximately 0.89 common unit, then approximately 80.3% of the common unit was converted into subordinate unit and the remaining 19.7% was converted into common unit.

During the years ended December 31, 2015, 2014 and 2013, unit-based compensation expense of $460,000,  $1,789,000 and $948,000, respectively, was recorded in general and administrative expense in the consolidated statements of operations related to these restricted units.

The following table presents restricted (non-vested) common, subordinated and class B common units during the years ended December 31, 2015, 2014 and 2013:

2015
	Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	31,012	$	24.36	126,553	$	24.36
Vested - service condition	(10,512)		25.37	(42,898)		25.37
Forfeited - service condition	(14,076)		22.89	(57,439)		22.89
Outstanding at the end of period	6,424		25.91	26,216		25.91

2014
	Class B Common Units			Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	177,867	$	25.58	—	$	—	—	$	—
Granted - service condition	90,000		19.64	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	(63,698)		24.21	—		—	—		—
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	(6,667)		34.91	—		—	—		—
Forfeited - performance condition	—		—	—		—	—		—
Conversion upon IPO	(197,502)		23.00	34,603		25.84	141,211		25.84
Granted - service condition	—		—	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	—		—	(876)		36.75	(3,576)		36.75
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	—		—	(2,715)		39.22	(11,082)		39.22
Forfeited - performance condition	—		—	—		—	—		—
Outstanding at the end of period	—		—	31,012		24.36	126,553		24.36

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8
2013
Restricted (Non-Vested) Common Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	143,000	$	20.32
Granted - service condition	68,500		34.91
Granted - performance condition	—		—
Vested - service condition	(23,633)		23.37
Vested - performance condition	—		—
Forfeited - service condition	(10,000)		19.51
Forfeited - performance condition	—		—
Outstanding at the end of period	177,867		25.58

We make distributions to non-vested restricted units on a 1:1 ratio with the per unit distributions paid to common units. Upon the vesting of the restricted units, we intend to settle these obligations with common units. Accordingly, we expect to recognize an aggregate of $561,000 of compensation expense related to non-vested restricted units over a weighted average period of 1.42 years.

15. Commitments and Contingencies

Legal Matters. We are involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on our consolidated financial statements.

Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.

Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting our activities. We have established procedures for the ongoing evaluation of our operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

We account for environmental contingencies in accordance with the ASC 410 related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.

Liabilities are recorded when environmental assessments and/or clean- ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, we had no significant environmental matters.

Refined Products Terminals. In the third quarter of 2014, we discovered that certain elements of the product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal could under-deliver refined products to our customers and, consequently, recognize excess gains on refined products generated through the terminal’s normal terminal and storage process. We recognize revenues for refined product gains as the products are sold at the terminal based on current market prices. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards and regulations, and have discussed this matter with our customers and have returned a certain amount of refined products to the majority of our customers. Because there are numerous elements inherent in the product measurement process that could affect the amount of refined product gains

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generated at the terminal, it is not practicable for us to accurately quantify this amount or the discrete period of refined product gains previously recognized that were caused by these specific issues. However, using available operational data and certain management assumptions, we have reasonably estimated the volume of refined products to be returned to our customers of approximately 24,000 barrels. During 2014, we returned approximately 20,900 barrels to our customers, which amounts to a value of $2,092,000. As of December 31, 2014, we had approximately 3,100 barrels remaining that were due to our customers, at an estimated value of $167,000. Accordingly, we recorded a $2,259,000 charge to operating expense in the consolidated statement of operations for the year ended December 31, 2014. We completed the final settlement of the under-delivered product volumes in the third quarter of 2015, which resulted in a charge to operating expenses of $172,000 in the year ended December 31, 2015.

Asset retirement obligations (ARO).  We have contractual obligations to perform dismantlement and removal activities in the event that some assets, such as storage tanks, are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. We have determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have either been in existence for many years or are relatively new assets and with regular maintenance will continue to be in service for many years to come. In addition, it is not possible to predict when demand for the service will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated ARO’s and therefore, no ARO liability is recorded as of December 31, 2015 and 2014. Additionally, many of these assets could be re-deployed for a similar use. We will continue to monitor these assets and if sufficient information becomes available for us to reasonably determine the settlement dates, an ARO will be recorded for these assets in the relevant periods.

Operating Leases.  We leases various buildings, land, storage facilities, transportation vehicles and office equipment under operating leases. Certain of the leases contain renewal and purchase options. Our aggregate rental expense for such leases was $5,741,000,  $4,806,000 and $3,299,000 for the years ended December 31, 2015, 2014 and 2013, respectively. Additionally, we assumed a land lease in the acquisition of Parnon Storage, LLC on August 3, 2012. Equal payments of $10,000 are due each month over the remaining 42 year lease period with no implied interest rate noted in the lease agreement.

Minimum future payments under non-cancelable operating leases as of December 31, 2015 and thereafter are as follows (in thousands):

2016	$	5,116
2017		4,331
2018		3,776
2019		2,383
2020		718
Thereafter		4,877
	$	21,201

16. Reportable Segments

In the fourth quarter of 2015, we reorganized our business segments to match the change in our internal organization and management structure.  The segment changes reflect the focus of our chief operating decision maker (“CODM”) and how performance of operations is evaluated and resources are allocated.  Therefore, the results of our formerly reported crude oil supply and logistics segment have been combined into our crude oil pipelines and storage segment.  As a result of the reorganization, our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales.  Accordingly, we have restated the items of segment information for the years ended December 31, 2014 and 2013 to reflect this new segment adjustment.

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Our operations are located in the United States and are organized into three reportable segments: crude oil pipelines and storage; refined products terminals and storage; and NGL distribution and sales.

Crude oil pipelines and storage.  The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and consists of approximately 148 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 140,000 barrels of storage capacity.  We also operate a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.

The crude oil pipelines and storage segment also consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. We conduct crude oil supply activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. We also own a fleet of crude oil gathering and transportation trucks operating in and around highly prolific drilling areas such as the Eagle Ford shale and the Permian Basin. As described in Note 3, the disposition of the Mid-Continent Business and Bakken Business impacts the crude oil pipelines and storage segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information tables. Accordingly, we have recast the segment information.

Refined products terminals and storage.  The refined products terminals and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal has storage capacity of 550,000 barrels from 11 tanks and has eight loading lanes with automated truck loading equipment. The Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment.  The North Little Rock terminal and the Caddo Mills terminal are primarily served by the Enterprise TE Products Pipeline Company LLC and the Explorer Pipeline, respectively.

NGL distribution and sales.  The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 48 states through a network of approximately 21,000 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the U.S., we sell NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. We also own a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.

Corporate and other. Corporate and other includes general partnership expenses associated with managing all of our reportable segments.

Our CODM evaluates the segments’ operating performance based on Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring.

F-40

The following tables reflect certain financial data for each reportable segment for the years ended December 31, 2015, 2014 and 2013.

	Year ended December 31,
	2015		2014		2013
	(in thousands)
External Revenues:
Crude oil pipelines and storage	$	480,527	$	495,971	$	186,993
Refined products terminals and storage		23,227		23,287		24,011
NGL distribution and sales		176,831		206,896		179,865
Total revenues	$	680,585	$	726,154	$	390,869
Cost of Sales, excluding depreciation and amortization:
Crude oil pipelines and storage	$	445,027	$	459,183	$	167,744
Refined products terminals and storage		8,649		6,453		4,683
NGL distribution and sales		76,618		126,686		105,488
Amounts not included in segment Adjusted EBITDA		(2,818)		13,360		(1,111)
Total cost of sales, excluding depreciation and amortization	$	527,476	$	605,682	$	276,804
Operating Expenses:
Crude oil pipelines and storage	$	9,238	$	7,928	$	7,405
Refined products terminals and storage		2,980		4,602		2,464
NGL distribution and sales		57,200		52,109		47,307
Amounts not included in segment Adjusted EBITDA		(41)		945		552
Total operating expenses	$	69,377	$	65,584	$	57,728
Depreciation and Amortization:
Crude oil pipelines and storage	$	20,356	$	17,240	$	10,335
Refined products terminals and storage		6,830		5,911		6,162
NGLs distribution and sales		18,628		16,163		13,981
Corporate and other		1,038		916		509
Total depreciation and amortization	$	46,852	$	40,230	$	30,987
Adjusted EBITDA:
Crude oil pipelines and storage	$	23,119	$	25,339	$	9,479
Refined products terminals and storage		10,867		10,723		16,100
NGL distribution and sales		30,896		15,511		15,518
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Capital Expenditures:
Crude oil pipelines and storage	$	42,919	$	36,691	$	4,410
Refined products terminals and storage		8,002		2,489		4,482
NGLs distribution and sales		18,587		16,557		16,009
Corporate and other		1,503		1,141		1,927
Total capital expenditures	$	71,011	$	56,878	$	26,828

F-41

A reconciliation of Adjusted EBITDA to net loss from continuing operations is included in the table below.

	Year ended December 31,
	2015		2014		2013
	(in thousands)
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Other expenses not allocated to reportable segments		(19,226)		(24,924)		(27,396)
Depreciation and amortization		(46,852)		(40,230)		(30,987)
Goodwill impairment		(29,896)		—		—
Interest expense		(5,375)		(8,981)		(8,245)
Loss on extinguishment of debt		—		(1,634)		—
Income tax expense		(754)		(300)		(208)
Loss on disposal of assets, net		(909)		(1,137)		(1,492)
Unit-based compensation		(1,217)		(1,658)		(790)
Total loss on commodity derivatives		(3,057)		(13,762)		902
Net cash payments for commodity derivatives settled during the period		14,821		1,071		209
Early settlement of commodity derivatives (1)		(8,745)		—		—
Corporate overhead support from general partner (2)		(5,500)		—		—
Transaction costs and other		(1,877)		(3,766)		(1,286)
Net loss from continuing operations	$	(43,705)	$	(43,748)	$	(28,196)

(1) Due to its non-recurring nature, we excluded this transaction in calculating Adjusted EBITDA.

(2) Represents expenses incurred by us that were absorbed by our general partner and not passed through to us.

Total assets from our reportable segments as of December 31 were as follows:

	December 31,		December 31,
	2015		2014
	(in thousands)
Crude oil pipelines and storage	$	408,304	$	451,518
Refined products terminals and storage		131,931		131,923
NGL distribution and sales		173,558		170,904
Corporate and other		12,092		21,958
Discontinued operations held for sale		9,374		36,870
Total assets	$	735,259	$	813,173

17. Related Parties

We perform certain management services for JP Development. We receive a monthly fee of $50,000 for these services. The monthly fee reduced general and administrative expenses in the consolidated statements of operations by $600,000 for the years ended December 31, 2015, 2014 and 2013, respectively. In the year ended December 31, 2015, we also performed certain additional services for which we received $228,000.

JP Development had a pipeline transportation business that provides crude oil pipeline transportation services to our discontinued Mid-Continent Business. As a result of utilizing JP Development’s pipeline transportation services during the years ended December 31, 2015, 2014 and 2013, we incurred pipeline tariff fees of $6,023,000,$8,875,000 and $8,514,000, respectively, which have been included in net loss from discontinued operations in the consolidated statements of operations. Such amounts were not settled in cash during the years ended December 31, 2013, rather, they were treated as deemed contributions/distributions from/to JP Development, as discussed in Note 1. As of December 31, 2015 and 2014, we had a net receivable from JP Development of $7,933,000 and $7,968,000, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided by JP Development. We recovered these amounts in full on February 1, 2016.

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As discussed in Note 11, on November 5, 2013, we issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. The interest rate was subject to an adjustment each quarter equal to the weighted average rate of JP Development’s outstanding indebtedness during the most recently ended fiscal quarter. Accrued interest on the note was payable quarterly in arrears. On March 20, 2014, the Partnership repaid this promissory note in full.

As discussed in Note 13, throughout 2013, we issued 88,114 Class C Common Units to JP Development for total net proceeds of $3,128,000.  

As discussed in Note 3, on February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area to JP Development in connection with JP Development’s sale of its GSPP pipeline assets to a third party.

As discussed in Note 13, on February 12, 2014, we issued 363,636 Class A Common Units to Lonestar for total net proceeds of $8,000,000 and on March 28, 2014, we issued 1,818,182 Series D Preferred Units to Lonestar for proceeds of $40,000,000. On October 7, 2014, we paid $42,436,000 from proceeds related to our IPO to redeem all then outstanding Series D Preferred Units.

As a result of the acquisition of our North Little Rock, Arkansas refined product terminal in November 2012, Truman Arnold Companies (‘TAC”) owns common and subordinated units in us. In addition, Mr. Greg Arnold, President and CEO of TAC, is also one of our directors and owns a 5% equity interest in our general partner. Our refined products terminals and storage segment sold refined products to TAC during 2014 and 2013. For the years ended December 31, 2014 and 2013, our revenue from TAC was $8,952,000, and $14,473,000, respectively.

Our NGL distribution and sales segment also purchases refined products from TAC. In 2015 and 2014, we paid $1,124,000 and $1,964,000 for refined product purchases from TAC, which is included in cost of sales in the consolidated statements of operations. As of December 31, 2015 and 2014, we had amounts due from TAC of $40,000 and $38,000, respectively, which is included in receivables from related parties in the consolidated balance sheets.

Through April of 2015 and during all of 2014 and 2013, we entered into transactions with CAMS Bluewire, an entity in which Arclight holds a non-controlling interest. CAMS Bluewire provides IT support for us. For the years ended December 31, 2015, 2014 and 2013, we paid $132,000,  $422,000 and $691,000, respectively for IT support and consulting services, and for purchases of IT equipment, which are included in operating expenses, general and administrative expenses and property plant and equipment in the consolidated statements of operations and the consolidated balance sheets. The total amount due to CAMS Bluewire as of December 31, 2014 was $32,000.

During the third quarter of 2014, we began performing certain management services for Republic Midstream, LLC (“Republic”), an entity owned by ArcLight. We charge a monthly fee of approximately $58,000 for these services. In December 2015, this monthly fee increased to approximately $75,000. The monthly fee reduced general and administrative expenses in the consolidated statements of operations by $712,000 and $297,000 for the years ended December 31, 2015 and 2014, respectively. During the second quarter of 2015, we began performing crude transportation and marketing services for Republic. We charged $3,049,000 for the year ended December 31, 2015, for these services which is included in gathering, transportation and storage fees – related parties and crude oil sales – related parties on the consolidated statements of operations. As of December 31, 2015 and 2014, we had a receivable balance due from Republic of $646,000 and $297,000, respectively, which is included in receivables from related parties in the consolidated balance sheets.

In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In addition, ArcLight reimbursed us for expenses we incurred for the year ended December 31, 2015. The total amounts paid on our behalf or reimbursed to us were $2,568,000 for the year ended December 31, 2015, and were treated as deemed contributions from ArcLight. In addition, during the year ended December 31, 2015, our general partner agreed to absorb $5,500,000 of corporate overhead expenses incurred by us and not pass such expense through to us.

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Beginning July 2013, we have no employees. The employees supporting our operations are employees of GP II, and as such, we fund GP II for payroll and other payroll-related expenses we incur. As of December 31, 2015 and 2014, we had a receivable balance due from GP II of $4,000 and $2,205,000, respectively, as a result of the timing of payroll funding, which is included in receivables from related parties in the consolidated balance sheet.

18.  Selected Quarterly Financial Data (unaudited)

Selected financial data by quarter is set forth in the table below:

	Quarter Ended
	March 31,		June 30,		September 30,		December 31,
		(in thousands, except per unit data)
2015
Total revenue	$	173,291	$	199,448	$	154,641	$	153,205
Operating income (loss)		2,185		(4,204)		(5,877)		(31,412)
Income (loss) from continuing operations		1,072		(5,479)		(7,201)		(32,097)
Income (loss) from discontinued operations		(407)		542		(1,247)		(13,839)
Net income (loss)		665		(4,937)		(8,448)		(45,936)
Basic and diluted income (loss) from continuing operations per common unit		0.03		(0.15)		(0.19)		(0.88)
Basic and diluted income (loss) from continuing operations per subordinated unit		0.03		(0.15)		(0.20)		(0.88)
Basic and diluted income (loss) per common unit		0.02		(0.13)		(0.23)		(1.26)
Basic and diluted income (loss) per subordinated unit		0.02		(0.14)		(0.23)		(1.26)
2014
Total revenue	$	130,958	$	175,008	$	213,922	$	206,266
Operating loss		(3,773)		(8,540)		(4,413)		(16,115)
Loss from continuing operations		(8,475)		(10,738)		(6,410)		(18,125)
Income (loss) from discontinued operations		(113)		(9,471)		800		(491)
Net loss		(8,588)		(20,209)		(5,610)		(18,616)
Basic and diluted loss from continuing operations per common and subordinated unit		—		—		—		(0.52)
Basic and diluted loss per common and subordinated unit		—		—		—		(0.51)

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Index to Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of JP Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014).
3.2	Third Amended and Restated Agreement of Limited Partnerships of JP Energy Partners LP dated October 7, 2014 (incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 7, 2014).
4.1	Registration Rights Agreement dated November 27, 2012 among JP Energy Partners LP, Arkansas Terminaling and Training Inc., Michal Coulson, Mary Ann Dawkins and White Properties II Limited Partnership (incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014).
10.1	Credit Agreement dated February 12, 2014 among JP Energy Partners LP, Bank of America, N.A. as administrative agent and swing line lender and an L/C issuer, the other lender parties thereto, and Bank of America Merrill Lynch and BMO Harris Financing, Inc., as joint lead arrangers and joint book managers (incorporated by reference to Exhibit 10.1 to the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014).
10.2	Amendment No. 1 to Credit Agreement, dated as of April 30, 2014 (incorporated by reference to Exhibit 10.2 to the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on May 8, 2014).
10.3	Amendment No. 2 and Waiver to Credit Agreement, dated as of August 5, 2014 (incorporated by reference to Exhibit 10.3 to the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on September 22, 2014).
10.4**	JP Energy Partners LP 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 7, 2014).
10.5	Right of First Offer Agreement dated as of October 7, 2014, by and among JP Energy Partners LP, JP Energy GP II LLC, JP Energy Development LP and Republic Midstream, Holdings LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 7, 2014).
10.6**	Employment Agreement of Patrick J. Welch (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 7, 2014).
10.7**	Employment Agreement of Jeremiah J. Ashcroft III (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K filed with the SEC on October 7, 2014).
10.8	Amendment No. 3 and Waiver to Credit Agreement dated as of September 19, 2014 (incorporated by reference to Exhibit 10.9 to the Partnership’s Registration Statement on Form S-1 (File No. 333-195787) filed with the SEC on September 22, 2014).
10.9	Amendment No. 4 to Credit Agreement dated as of November 6, 2015 (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed with the SEC on November 9, 2015).
10.10*	Amendment No. 5 to Credit Agreement dated February 23, 2016.

106

Exhibit Number	Description
10.11***	Employment Agreement of Simon Chen dated as of October 21, 2015.
21.1*	List of Subsidiaries of JP Energy Partners LP.
23.1*	Consent of Pricewaterhouse Coopers LLP.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Calculation Linkbase
101.DEF*	XBRL Taxonomy Definition Linkbase
101.LAB*	XBRL Taxonomy Label Linkbase
101.PRE*	XBRL Taxonomy Presentation Linkbase

* Filed Herewith

** Management contract or compensatory plan or arrangement

*** Management contract or compensatory plan or arrangement filed herewith

107

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	JP Energy Partners LP
	By:	JP Energy GP II LLC, its general partner
Date: February 29, 2016	By:	/s/ J. Patrick Barley
		J. Patrick Barley
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ J. Patrick Barley	Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
J. Patrick Barley		February 29, 2016
/s/ Patrick J. Welch	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)
Patrick J. Welch		February 29, 2016
/s/ Shiming Chen	Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)	February 29, 2016
Shiming Chen
/s/ Greg Arnold	Director	February 29, 2016
Greg Arnold
/s/ John F. Erhard	Director	February 29, 2016
John F. Erhard
/s/ Daniel R. Revers	Director	February 29, 2016
Daniel R. Revers
/s/ Evan M. Schwartz	Director	February 29, 2016
Evan M. Schwartz
/s/ Josh L. Sherman	Director	February 29, 2016
Josh L. Sherman
/s/ Norman J. Szydlowski	Director	February 29, 2016
Norman J. Szydlowski
/s/ T. Porter Trimble	Director	February 29, 2016
T. Porter Trimble

108

EX-10.10

Exhibit 10.10

Execution Version

AMENDMENT NO. 5 TO CREDIT AGREEMENT

This Amendment No. 5 to Credit Agreement (this “Agreement”) dated as of February 23, 2016 (the “Effective Date”) is among JP Energy Partners LP, a Delaware limited partnership (the “Borrower”), JP Energy Refined Products, LLC, a Delaware limited liability company, JP Energy ATT, LLC, a Delaware limited liability company, JP Energy Caddo, LLC, a Delaware limited liability company, Pinnacle Propane, LLC, a Texas limited liability company, Pinnacle Propane Express, LLC, a Delaware limited liability company, Alliant Gas, LLC, a Texas limited liability company, JP Energy Crude Oil Services, LLC, a Delaware limited liability company, JP Falco, LLC, a Delaware limited liability company, JP Energy Storage, LLC, a Oklahoma limited liability company, JP Energy Permian, LLC, a Delaware limited liability company, JP Energy Products Supply, LLC, a Delaware limited liability company, and JP Liquids, LLC, a Delaware limited liability company, (each a “Guarantor”), the undersigned Lenders (as defined below) and Bank of America, N.A., as Administrative Agent for the Lenders (in such capacity, the “Administrative Agent”), Swing Line Lender and L/C Issuer.

INTRODUCTION

A. The Borrower, the financial institutions party thereto as Lenders (the “Lenders”), and the Administrative Agent have entered into the Credit Agreement dated as of February 12, 2014 (as amended, restated, or modified from time to time, the “Credit Agreement”).

B. The Borrower has notified the Administrative Agent that (i) the Consolidated Working Capital of the Borrower may be less than $15,000,000 as of the last day of the fiscal quarter ending December 31, 2015, which would constitute an Event of Default under Section 8.01(b) of the Credit Agreement with respect to Section 7.11(b) of the Credit Agreement (the “Financial Covenant Default”), and (ii) certain Loan Parties have opened the deposit accounts described on Schedule I hereto without giving prior written notice to the Administrative Agent, which would constitute an Event of Default under Section 8.01(c) of the Credit Agreement with respect to Section 4(g)(ii) of the Security Agreement (the “Deposit Account Default”, and together with the Financial Covenant Default and any Default or Event of Default that would arise solely (a) from any failure of the Borrower to give notice of the Financial Covenant Default or the Deposit Account Default pursuant to Section 6.03(a) of the Credit Agreement or (b) from any breach of the representation and warranty contained in Section 5.07 of the Credit Agreement that would arise solely from the existence of the Financial Covenant Default or the Deposit Account Default, the “Subject Default”).

C. The Borrower has requested that the Administrative Agent, the Lenders, the L/C Issuer and the Swing Line Lender agree to make certain amendments to the Credit Agreement and grant certain waivers with respect to the Subject Default, as set forth herein.

THEREFORE, in fulfillment of the foregoing, the Borrower, the Administrative Agent, the L/C Issuer, the Swing Line Lender and each of the undersigned Lenders hereby agree as follows:

Section 1. Definitions; References.  Unless otherwise defined in this Agreement, each term used in this Agreement which is defined in the Credit Agreement has the meaning assigned to such term in the Credit Agreement.

Section 2. Amendments to Credit Agreement. 

(a) The definition of “Defaulting Lender” in Section 1.01 of the Credit Agreement is hereby amended by replacing it with the following:

“Defaulting Lender” means, subject to Section 2.16(b), any Lender that (a) has failed to (i) fund all or any portion of its Loans within two Business Days of the date such Loans were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Lender’s determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable default, shall be specifically identified in such writing) has not been satisfied, or (ii) pay to the Administrative Agent, any L/C Issuer, the Swing Line Lender or any other Lender any other amount required to be paid by it hereunder (including in respect of its participation in Letters of Credit or Swing Line Loans) within two Business Days of the date when due, (b) has notified the Borrower, the Administrative Agent, the L/C Issuers or the Swing Line Lender in writing that it does not intend to comply with its funding obligations hereunder, or has made a public statement to that effect (unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s determination that a condition precedent to funding (which condition precedent, together with any applicable default, shall be specifically identified in such writing or public statement) cannot be satisfied), (c) has failed, within three Business Days after written request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent and the Borrower), or (d) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such a capacity, or (iii) become the subject of a Bail-in Action; provided that a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of any Equity Interest in that Lender or any direct or indirect parent company thereof by a Governmental Authority so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender.  Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (a) through (d) above, and of the effective date of such status, shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section 2.16(b)) as of the date established therefor by the Administrative Agent in a written notice of such determination, which shall be delivered by the Administrative Agent to the Borrower, each L/C Issuer, the Swing Line Lender and each Lender promptly following such determination.

(b) Section 1.01 of the Credit Agreement is hereby amended by inserting the following new defined terms in the appropriate alphabetical order as follows:

“Available Liquidity” means at any time, the sum of (a) unrestricted cash and Cash Equivalents held by the Loan Parties at such time and (b) the lesser of (i) the

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excess of (x) the Aggregate Commitments at such time over (y) the Total Outstandings at such time and (ii) the maximum amount of such excess described in clause (b)(i) that the Borrower could borrow hereunder at such time and remain in compliance with Section 7.11(d) and, if applicable, Section 7.11(f), in each case, to be determined on the basis of the financial information most recently delivered to the Administrative Agent and the Lenders pursuant to Section 6.01(a) or (b) as of such time.

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Fifth Amendment Effective Date” means February23, 2016.

“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule. 

(c) Section 2.16(a) is hereby amended by replacing clause (iv) thereof in its entirety with the following:

(iv)Reallocation of Applicable Percentages to Reduce Fronting Exposure.  All or any part of such Defaulting Lender’s participation in L/C Obligations and Swing Line Loans shall be reallocated among the Non-Defaulting Lenders in accordance with their respective Applicable Percentages (calculated without regard to such Defaulting Lender’s Commitment) but only to the extent that (x) the conditions set forth in Section 4.02 are satisfied at the time of such reallocation

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(and, unless the Borrower shall have otherwise notified the Administrative Agent at such time, the Borrower shall be deemed to have represented and warranted that such conditions are satisfied at such time), and (y) such reallocation does not cause the aggregate Revolving Credit Exposure of any Non-Defaulting Lender to exceed such Non-Defaulting Lender’s Commitment.  Subject to Section 10.20, no reallocation hereunder shall constitute a waiver or release of any claim of any party hereunder against a Defaulting Lender arising from that Lender having become a Defaulting Lender, including any claim of a Non-Defaulting Lender as a result of such Non-Defaulting Lender’s increased exposure following such reallocation. 

(d) Section 1.01 of the Credit Agreement is hereby amended by deleting the defined terms “Consolidated Working Capital”, “Consolidated Current Assets”, and “Consolidated Current Liabilities” in their entirety.

(e) Article V of the Credit Agreement is hereby amended by inserting the following new Section 5.24 in the appropriate numerical order as follows:

5.24EEA Financial Institution.Neither the Borrower nor any Guarantor is an EEA Financial Institution.

(f) Section 6.17(b)(ii) and (c)(ii) are hereby amended by adding the following proviso to the end thereof:

provided, that for purposes of calculating compliance with Section 7.11(g), unrestricted cash and Cash Equivalents, Aggregate Commitments and Total Outstandings shall be determined as of the date of such designation

(g) Section 7.03(g)(iii) is hereby amended by adding the following proviso to the end thereof:

provided, that for purposes of calculating compliance with Section 7.11(g), unrestricted cash and Cash Equivalents, Aggregate Commitments and Total Outstandings shall be determined as of the date of such Acquisition.

(h) Section 7.06(e) is hereby amended by adding the following proviso to the end thereof:

provided further, that for purposes of calculating compliance with Section 7.11(g), unrestricted cash and Cash Equivalents, Aggregate Commitments and Total Outstandings shall be determined as of the date of such Restricted Payment.

(i) Section 7.11(b) is hereby amended and restated in its entirety as follows:

(b)[intentionally omitted]

(j) Section 7.11(d) is hereby amended and restated in its entirety as follows:

(d)Consolidated Net Total Leverage Ratio.  For any fiscal quarter ending on or after the IPO Closing Date, permit the Consolidated Net Total Leverage Ratio as of the end of any such fiscal quarter, (x) if a Qualified Offering has not been consummated, to be greater than 4.50 to 1.00 and (y) if a Qualified Offering has been consummated, to be greater than 5.00 to 1.00. 

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(k) Section 7.11 is hereby amended by inserting the following new clause (g) in the appropriate alphabetical order:

(g)Available Liquidity.  Commencing as of the Fifth Amendment Effective Date, permit the Available Liquidity of the Loan Parties to be less than $25,000,000 as of the last day of any fiscal quarter.

(l) The Credit Agreement is hereby amended by renumbering Section 10.20 as Section 10.21 and inserting the following new Section 10.20 in the appropriate numerical order as follows:

10.20Acknowledgement and Consent to Bail-In of EEA Financial Institutions.Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Lender, L/C Issuer or Swing Line Lender that is an EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any Lender, L/C Issuer or Swing Line Lender that is an EEA Financial Institution; and

(b)the effects of any Bail-in Action on any such liability, including, if applicable:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

(m) The Credit Agreement is hereby further amended by replacing Exhibit D with the Exhibit D attached hereto. 

Section 3. Waiver. The Lenders hereby waive the Subject Default, which waiver, in the case of the Subject Default, shall be effective as of the date of occurrence of the Subject Default.  This waiver is limited to the extent described herein and shall not be construed to be a waiver of any other terms, provisions, covenants, warranties or agreements contained in the Credit Agreement or any of the Loan Documents, including any requirement for delivery of Control Agreements with respect to the deposit accounts described on Schedule I hereto, or a waiver of any Default or Event of Default that may have occurred or may hereafter occur (other than the Subject Default).  Without limiting the foregoing, failure to observe or perform any agreement contained in Section 7.11 of the Credit Agreement or Section 4 of the Security Agreement shall constitute a Default and Event of Default. The Administrative Agent and the Lenders reserve the right to

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exercise any rights and remedies available to them in connection with any present or future defaults under the Credit Agreement or any other provision of any Loan Document other than the Subject Default.

Section 4. Reaffirmation of Liens; Reaffirmation of Guaranty. 

(a) Each of the Borrower and each Guarantor (i) is party to certain Collateral Documents securing and supporting the Borrower’s obligations under the Loan Documents, (ii) represents and warrants that it has no defenses to the enforcement of the Collateral Documents and that according to their terms the Collateral Documents will continue in full force and effect to secure the Borrower’s obligations under the Loan Documents, as the same may be amended, supplemented, or otherwise modified, and (iii) acknowledges, represents, and warrants that the liens and security interests created by the Collateral Documents are valid and subsisting and create a perfected Lien in the Collateral to the extent, and with the priority, contemplated by the Collateral Documents to secure the Borrower’s obligations under the Loan Documents, as the same may be amended, supplemented, or otherwise modified.

(b) Each Guarantor hereby ratifies, confirms, and acknowledges that its obligations under the Loan Documents are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment and performance, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations, as such Obligations may have been amended by this Agreement.  Each Guarantor hereby acknowledges that its execution and delivery of this Agreement do not indicate or establish an approval or consent requirement by such Guarantor under the Credit Agreement in connection with the execution and delivery of amendments, modifications or waivers to the Credit Agreement or any of the other Loan Documents.

Section 5. Representations and Warranties.  The Borrower represents and warrants to the Administrative Agent and the Lenders that:

(a) the representations and warranties set forth in the Credit Agreement and in the other Loan Documents are true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which shall be true and correct in all respects) as of the date of this Agreement except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which shall be true and correct in all respects) as of such earlier date;

(b) (i) the execution, delivery, and performance of this Agreement are within the corporate, limited partnership or limited liability company power, as appropriate, and authority of the Borrower and the Guarantors and have been duly authorized by appropriate proceedings and (ii) this Agreement constitutes a legal, valid, and binding obligation of the Borrower and each Guarantor, enforceable against the Borrower and each such Guarantor in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; and

(c) as of the effectiveness of this Agreement and after giving effect thereto, no Default or Event of Default has occurred and is continuing.

Section 6. Effectiveness.  This Agreement shall become effective as of the date hereof upon the occurrence of all of the following:

(a) Documentation. The Administrative Agent shall have received this Agreement, duly and validly executed by the Required Lenders and the Borrower and delivered to the Administrative Agent, in form and substance satisfactory to the Administrative Agent and the Required Lenders, in sufficient copies for each Lender;

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(b) Representations and Warranties.  The representations and warranties in this Agreement and the other Loan Documents being true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which shall be true and correct in all respects) as of the date of this Agreement except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which shall be true and correct in all respects) as of such earlier date, and except that the representations and warranties contained in Sections 5.05(a) and (b) of the Credit Agreement shall be deemed to refer to the most recent statements furnished pursuant to clauses (a) and (b), respectively, of Sections 6.01 of the Credit Agreement.

(c) No Default or Event of Default. After giving effect to this Agreement, there being no Default or Event of Default which has occurred and is continuing.

(d) Expenses.  The Borrower having paid all costs, expenses, and fees which have been invoiced and are payable pursuant to Section 10.04 of the Credit Agreement or any other written agreement.

(e) Amendment Fee. The Administrative Agent shall have received from the Borrower, for the account of each Lender that executes and delivers a signature page hereto to the Administrative Agent by 4:00 p.m. (CST) on or before February 19, 2016 (each such Lender, a “Consenting Lender”, and collectively, the “Consenting Lenders”), an amendment fee in an amount equal to 5 basis points on the aggregate Commitments of such Consenting Lender.

Section 7. Effect on Loan Documents.  Except as amended and waived herein, the Credit Agreement and the Loan Documents remain in full force and effect as originally executed, and nothing herein shall act as a waiver of any of the Administrative Agent’s or Lenders’ rights under the Loan Documents, as amended.  This Agreement is a Loan Document for the purposes of the provisions of the other Loan Documents.  Without limiting the foregoing, any breach of representations, warranties, and covenants under this Agreement may be a Default or Event of Default under other Loan Documents.

Section 8. Choice of Law.  This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York.

Section 9. Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original.

THIS WRITTEN AGREEMENT AND THE LOAN DOCUMENTS, AS DEFINED IN THE CREDIT AGREEMENT, REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[The remainder of this page has been left blank intentionally.]

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EXECUTED as of the date first set forth above.

BORROWER:
JP ENERGY PARTNERS LP
By:  JP Energy GP II LLC, its general partner
By:	/s/ Patrick Welch
Name:	Patrick Welch
Title:	Chief Financial Officer
GUARANTORS:
JP ENERGY REFINED PRODUCTS, LLC
JP ENERGY ATT, LLC
JP ENERGY CADDO, LLC
JP ENERGY CRUDE OIL SERVICES, LLC
JP FALCO, LLC
JP ENERGY STORAGE, LLC
JP ENERGY PERMIAN, LLC
JP ENERGY PRODUCTS SUPPLY, LLC
By:	/s/ Patrick Welch
Name:	Patrick Welch
Title:	Chief Financial Officer
PINNACLE PROPANE, LLC
PINNACLE PROPANE EXPRESS, LLC
ALLIANT GAS, LLC
JP LIQUIDS, LLC
By:	/s/ Patrick Welch
Name:	Patrick Welch
Title:	Chief Financial Officer

SIGNATURE PAGE TO AMENDMENT NO. 5

JP ENERGY PARTNERS LP

ADMINISTRATIVE AGENT:
BANK OF AMERICA, N.A.,
as Administrative Agent
By:	/s/ Don B. Pinzon
Name:	Don B. Pinzon
Title:	Vice President

SIGNATURE PAGE TO AMENDMENT NO. 5

JP ENERGY PARTNERS LP

LENDERS:
BANK OF AMERICA, N.A., as a Lender, L/C Issuer, and Swing Line Lender
By:	/s/ Julie Castano
Name:	Julie Castano
Title:	Senior Vice President

SIGNATURE PAGE TO AMENDMENT NO. 5

JP ENERGY PARTNERS LP

BANK OF MONTREAL, as a Lender
By:	/s/ Kevin Utsey
Name:	Kevin Utsey
Title:	Director

SIGNATURE PAGE TOAMENDMENT NO. 5

JP ENERGY PARTNERS LP

/s/
	DEUTSCHE BANK AG NEW YORK BRANCH, as a Lender
	By:	/s/ Chris Chapman
	Name:	Chris Chapman
	Title:	Director
	By:	/s/ Shai Bandner
	Name:	Shai Bandner
	Title:	Vice President

SIGNATURE PAGE TOAMENDMENT NO. 5

JP ENERGY PARTNERS LP

ZB, N.A. dba Amegy Bank,   as a Lender
By:	/s/ Jill McSorley
Name:	Jill McSorley
Title:	Senior Vice President – Amegy Bank Division

SIGNATURE PAGE TO AMENDMENT NO. 5

JP ENERGY PARTNERS LP

ROYAL BANK OF CANADA, as a Lender
By:	/s/ Jay Sartain
Name:	Jay Sartain
Title:	Authorized Signatory

SIGNATURE PAGE TOAMENDMENT NO. 5

JP ENERGY PARTNERS LP

CADENCE BANK, N.A. , as a Lender
By:	/s/ William W. Brown
Name:	William W. Brown
Title:	Senior Vice President

SIGNATURE PAGE TOAMENDMENT NO. 5

JP ENERGY PARTNERS LP

BARCLAYS BANK PLC,   as a Lender
By:	/s/ Vanessa A. Kurbatskiy
Name:	Vanessa A. Kurbatskiy
Title:	Vice President

SIGNATURE PAGE TOAMENDMENT NO. 5

JP ENERGY PARTNERS LP

SCHEDULE I

Deposit Accounts

Depositary Bank	Account Number	Loan Party	Dated Opened	Balance as of February 15, 2016
Wells Fargo Bank, N.A.	4120161526	JP Energy Products Supply, LLC	November 2015	$0
Wells Fargo Bank, N.A.	4124847047	JP Energy Storage, LLC	December 2015	$500
Wells Fargo Bank, N.A.	9673451606	JP Energy Services, LLC	September 2015	$0
Wells Fargo Bank, N.A.	9679451600	JP Energy Products Supply, LLC	November 2015	$0

SCHEDULE I

AMENDMENT NO. 5

EXHIBIT D

FORM OF COMPLIANCE CERTIFICATE

Financial Statement Date:  ________, ____

To:Bank of America, N.A., as Administrative Agent

Ladies and Gentlemen:

Reference is made to that certain Credit Agreement, dated as of February 12, 2014 (as amended, restated, extended, supplemented or otherwise modified in writing from time to time, the “Agreement;” the terms defined therein being used herein as therein defined), among JP Energy Partners LP, a Delaware limited partnership (the “Borrower”), the Lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, as Swing Line Lender and as an L/C Issuer.

The undersigned Responsible Officer hereby certifies as of the date hereof that he/she is the ___________________________________ of the Borrower, and that, as such, he/she is authorized to execute and deliver this Certificate to the Administrative Agent on the behalf of the Borrower, and that:

[Use following paragraph 1 for fiscal year-end financial statements]

1.The Borrower has delivered the year-end audited financial statements required by Section 6.01(a)(i) [and (ii)] of the Agreement for the fiscal year of the Borrower ended as of the above date, together with the report and opinion of an independent certified public accountant required by Section 6.01(a)(i).  [The financial statements required by Section 6.01(a)(ii)fairly present the financial condition, results of operations, partners’ capital and cash flows of the Borrower and its Restricted Subsidiaries in accordance with GAAP, subject only to the absence of certain footnotes included in the audited financial statements to the extent not applicable to the Restricted Subsidiaries.]

[Use following paragraph 1 for fiscal quarter-end financial statements]

1.The Borrower has delivered the unaudited financial statements required by Section 6.01(b)(i) [and (ii)] of the Agreement for the fiscal quarter of the Borrower ended as of the above date.  The financial statements required by Section 6.01(b)(i) fairly present the financial condition, results of operations, partners’ capital and cash flows of the Borrower and its consolidated Subsidiaries in accordance with GAAP as at such date and for such period, subject only to normal year-end audit adjustments and the absence of footnotes. [The financial statements required by Section 6.01(b)(ii)fairly present the financial condition, results of operations, partners’ capital and cash flows of the Borrower and its Restricted Subsidiaries in accordance with GAAP, subject only to normal year-end audit adjustments and the absence of footnotes.]

2.The undersigned has reviewed and is familiar with the terms of the Agreement and has made, or has caused to be made under his/her supervision, a detailed review of the transactions and condition (financial or otherwise) of the Borrower during the accounting period covered by such financial statements.

3.A review of the activities of the Borrower during such fiscal period has been made under the supervision of the undersigned with a view to determining whether during such fiscal period the Borrower performed and observed all its Obligations under the Loan Documents, and

[select one:]

[to the best knowledge of the undersigned, during such fiscal period the Borrower performed and observed each covenant and condition of the Loan Documents applicable to it, and no Default has occurred and is continuing.]

EXHIBIT D

AMENDMENT NO. 5

--or--

[to the best knowledge of the undersigned, the following covenants or conditions have not been performed or observed and the following is a list of each such Default and its nature and status:]

4.The representations and warranties of the Borrower and each other Loan Party contained in Article V of the Agreement or any other Loan Document, or which are contained in any document furnished at any time under or in connection therewith, are true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which are true and correct in all respects) on and as of the date hereof, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except for such representations and warranties that have a materiality or Material Adverse Effect qualification, which shall be true and correct in all respects) as of such earlier date, and except that for purposes of this Compliance Certificate, the representations and warranties contained in Sections 5.05(a) and (b) of the Agreement shall be deemed to refer to the most recent statements furnished pursuant to Sections 6.01(a) and (b) of the Agreement, respectively, including the statements in connection with which this Compliance Certificate is delivered.

5.The financial covenant analyses and information set forth on Schedules 1,  2, and 3 attached hereto are true and accurate on and as of the date of this Certificate.

6.[The reconciliation set forth on Schedule 4 attached hereto accurately and correctly reconciles each of the components reflected in the financial covenant calculations set forth in Schedules 1,  2 and 3 hereto to the corresponding consolidated amounts set forth in the financial statements delivered pursuant to this Compliance Certificate.]  1

IN WITNESS WHEREOF, the undersigned has executed this Certificate as
of __________________,________________.

JP ENERGY PARTNERS LP

a Delaware limited partnership

By:  JP Energy GP II LLC,

its general partner

By:

Name:

Title:

1To be included for any fiscal quarter during which an Unrestricted Subsidiary exists.

EXHIBIT D

AMENDMENT NO. 5

For the Quarter/Year ended ___________________, ____ (“Statement Date”)

SCHEDULE 1
to the Compliance Certificate

I.	Section 7.11(a) – Consolidated Interest Coverage Ratio.
	A.	Consolidated EBITDA for Measurement Period ending on above date (“Subject Period”) as set forth on Schedule 2 hereto:	$______
	B.	Consolidated Interest Charges for Subject Period:	$______
	C.	Consolidated Interest Coverage Ratio (Line I.A  Line I.B):	____ to 1
		Minimum required: 2.50 to 1.00
II.	Section 7.11(d) – Consolidated Net Total Leverage Ratio.
	A.	Consolidated Net Funded Indebtedness at Statement Date as set forth on Schedule 3 hereto:	$______
	B.	Consolidated EBITDA for Subject Period (Line I.A above):2	$______
	C.	Consolidated Net Total Leverage Ratio (Line II.A  Line II.B):	____ to 1
		Maximum permitted: A Qualified Offering has not been consummated: 4.50 to 1.00 A Qualified Offering has been consummated: 5.00 to 1.00
III.	Section 7.11(f)  – Consolidated Senior Secured Net Leverage Ratio.3
	A.	Consolidated Senior Secured Indebtedness at Statement Date:	$______
	B.	Consolidated EBITDA for Subject Period (Line I.A above):4	$______

2  For purposes of calculating Consolidated Net Total Leverage Ratio and Consolidated Senior Secured Net Leverage Ratio, Consolidated EBITDA may include, at Borrower’s option, any Material Project EBITDA Adjustments, and shall be calculated, on a Pro Forma Basis, after giving effect to, without duplication, any Material Acquisition (as defined below) and any Material Disposition (as defined below) and, at the Borrower’s election, any other Permitted Acquisition or permitted Disposition, in each case, occurring during such Measurement Period, as if such Acquisition or Disposition, and any related incurrence or repayment of Indebtedness, occurred on the first day of such Measurement Period.  For the avoidance of doubt and, in the case of JP Permian, only to the extent not otherwise addressed in the fourth footnote in Schedule 3, with respect to the assets and Equity Interests comprising the Closing Date Drop Downs, the Borrower shall be deemed to have acquired such assets pursuant to a Material Acquisition as of the date such assets were initially acquired by JP Development for purposes of calculating Consolidated EBITDA on a Pro Forma Basis for purposes of calculating the Consolidated Total Leverage Ratio, the Consolidated Net Total Leverage Ratio, the Consolidated Senior Secured Leverage Ratio and the Consolidated Senior Secured Net Leverage Ratio.  As used in the Agreement, “Material Acquisition” means any Permitted Acquisition with Acquisition Consideration of $5,000,000 or more and “Material Disposition” means any permitted Disposition resulting in net sale proceeds of $5,000,000 or more.

3  To be calculated as of the end of any fiscal quarter occurring on or after a Qualified Offering and on or after the IPO Closing Date.

EXHIBIT D

AMENDMENT NO. 5

	C.	Consolidated Senior Secured Net Leverage Ratio (Line III.A  Line III.B):	$______
		Maximum permitted: 3.50:1.00
IV.	Section 7.11(g) – Available Liquidity.5
	A.	unrestricted cash and Cash Equivalents of the Loan Parties at Statement Date:	$______
	B.	Lesser of Line B.IV.3 and Line B.IV.4:	$______
		1.  Aggregate Commitments at Statement Date:	$______
		2.  Total Outstandings at Statement Date:	$______
		3.  Line IV.B.1  Line IV.B.2:	$______
		4.  Maximum amount of Line IV.B.3 that Borrower could borrow as of Statement Date and remain in compliance with the Consolidated Net Total Leverage Ratio at Statement Date:	$______
	C.	Line IV.A + Line IV.B:	$______
		Minimum required: $25,000,000
V.	Section 6.02(a)(i) – Immaterial Subsidiaries.6
	A.	total assets
		1.  total assets of all Immaterial Subsidiaries, taken as a whole:	$______
		2. total assets of Borrower and its Restricted Subsidiaries:	$______
		3. percentage of total assets (line V.A.1  line V.A.2):	______%
	B.	Consolidated EBITDA for Subject Period:

4For purposes of calculating Consolidated Net Total Leverage Ratio and Consolidated Senior Secured Net Leverage Ratio, Consolidated EBITDA may include, at Borrower’s option, any Material Project EBITDA Adjustments, and shall be calculated, on a Pro Forma Basis, after giving effect to, without duplication, any Material Acquisition (as defined below) and any Material Disposition (as defined below) and, at the Borrower’s election, any other Permitted Acquisition or permitted Disposition, in each case, occurring during such Measurement Period, as if such Acquisition or Disposition, and any related incurrence or repayment of Indebtedness, occurred on the first day of such Measurement Period.  For the avoidance of doubt and, in the case of JP Permian, only to the extent not otherwise addressed in the fourth footnote in Schedule 3, with respect to the assets and Equity Interests comprising the Closing Date Drop Downs, the Borrower shall be deemed to have acquired such assets pursuant to a Material Acquisition as of the date such assets were initially acquired by JP Development for purposes of calculating Consolidated EBITDA on a Pro Forma Basis for purposes of calculating the Consolidated Total Leverage Ratio, the Consolidated Net Total Leverage Ratio, the Consolidated Senior Secured Leverage Ratio and the Consolidated Senior Secured Net Leverage Ratio.  As used in the Agreement, “Material Acquisition” means any Permitted Acquisition with Acquisition Consideration of $5,000,000 or more and “Material Disposition” means any permitted Disposition resulting in net sale proceeds of $5,000,000 or more.

5  To be calculated commencing with the Fifth Amendment Effective Date.

6To be calculated as of the end of any period during which an Immaterial Subsidiary exists.

EXHIBIT D

AMENDMENT NO. 5

	1.  Consolidated EBITDA for all Immaterial Subsidiaries, taken as a whole:	$______
	2. Consolidated EBITDA for Borrower and its Restricted Subsidiaries (Line I.A above):	$______
	3. percentage of Consolidated EBITDA (line V.B.1  line V.B.2)	______%
C.	Immaterial Subsidiary (Line V.A.3 or Line V.B.3):	[Yes][No]
	Maximum permitted: 2.5%

EXHIBIT D

AMENDMENT NO. 5

For the Quarter/Year ended ___________________(“Statement Date”)

SCHEDULE 2
to the Compliance Certificate
Consolidated EBITDA
(in accordance with the definition of Consolidated EBITDA
as set forth in the Agreement)

EBITDA
Consolidated EBITDA	Quarter Ended __________	Quarter Ended __________	Quarter Ended __________	Quarter Ended __________	Twelve Months Ended __________
Consolidated Net Income
+Consolidated Interest Charges
+ income taxes7
+depreciation expense
+amortization expense8
+ non-recurring non-cash expenses
+ Transaction Costs9
-income tax credits
-non-cash income
=Consolidated EBITDA10

7  Including franchise or margin taxes imposed in lieu of income taxes by the State of Texas on gross receipts.

8Including amortization of debt issuance costs.

9Such amounts added back (i) with respect to the IPO and the Agreement shall not exceed $10,000,000 and (ii) in all other cases shall not exceed 10% of Consolidated EBITDA prior to such adjustment.

10Notwithstanding the foregoing, the Consolidated EBITDA of JP Permian for purposes of calculating the Consolidated Total Leverage Ratio, the Consolidated Net Total Leverage Ratio, the Consolidated Senior Secured Leverage Ratio, the Consolidated Senior Secured Net Leverage Ratio and the Consolidated Interest Coverage Ratio shall be: (a) for the calculations to be made for the fiscal quarter ending December 31, 2013, the Consolidated EBITDA of JP Permian for the calendar month ending December 31, 2013 multiplied by twelve; (b) for the calculations to be made for the fiscal quarter ending March 31, 2014, the Consolidated EBITDA of JP Permian for such fiscal quarter multiplied by four; (c) for the calculations to be made for the fiscal quarter ending June 30, 2014, the Consolidated EBITDA of JP Permian for the two-fiscal quarter period then ended multiplied by two; (d) for the calculations to be made for the fiscal quarter ending September 30, 2014, the Consolidated EBITDA of JP Permian for the three-fiscal quarter period then ended multiplied by 4/3; and (e) for the calculations to be made for each fiscal quarter ending or on after December 31, 2014, the Consolidated EBITDA of JP Permian for the Measurement Period then ended.

EXHIBIT D

AMENDMENT NO. 5

For the Quarter/Year ended ___________________(“Statement Date”)

SCHEDULE 3
to the Compliance Certificate

Consolidated Net Funded Indebtedness
(in accordance with the definition of Consolidated Net
Funded Indebtedness as set forth in the Agreement)

Funded Indebtedness
Consolidated Net Funded Indebtedness	Quarter Ended __________
Principal obligations11
+purchase money Indebtedness
+reimbursement obligations under letters of credit, etc.
+obligations for the deferred purchase price
+Attributable Indebtedness
+ Guarantees
+ Indebtedness of partnership or joint venture unless Non-Recourse Debt
=Consolidated Funded Indebtedness12
-  the lesser of (a) $7,500,000 and (b) cash and Cash Equivalents held by the Borrower and its Restricted Subsidiaries at Statement Date (excluding restricted cash)
= Consolidated Net Funded Indebtedness

11Other than the outstanding amount of undrawn L/C Obligations.

12Consolidated Funded Indebtedness shall not include (i) cash purchase price adjustments or cash earnouts in connection with any Acquisition until such time as the amount payable pursuant to such purchase price adjustment or earnout is determinable and non-contingent and (ii) all liabilities in respect of Swap Contracts not then due and owing.

EXHIBIT D

AMENDMENT NO. 5

For the Quarter/Year ended ___________________(“Statement Date”)

SCHEDULE 4
to the Compliance Certificate

Reconciliation

EXHIBIT D

AMENDMENT NO. 5

EX-10.11

Exhibit 10.11

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is made effective as of October 21, 2015, by and between JP Energy GP II LLC, a Delaware limited liability company (the “Company”), and Simon Chen (the “Employee”).

WHEREAS, the Employee has been providing services to the Company as an executive officer of the Company as the Company’s Vice President, Chief Accounting Officer and Controller;  

WHEREAS, the Employee previously or may in the future enter into one or more restricted unit or other equity incentive award agreements with the Company, JP Energy Partners LP (the “Partnership”) and/or their Affiliates (the “Award Agreements”);

WHEREAS, the Company and the Employee desire to enter into an employment agreement that governs the terms and conditions of the Employee’s employment from this date forward;

WHEREAS, pursuant to this Agreement, the Employee shall be employed by the Company in a confidential and fiduciary relationship, and Confidential Information (as defined in Section 9.A. hereof) will necessarily be provided to, communicated to, or acquired by the Employee by virtue of his employment with the Company; and

WHEREAS, for purposes of this Agreement, “Business” shall mean any business or activity in which the Company, the Partnership, JP Energy Development LP (“DevCo”) or any of their subsidiaries or affiliates (collectively, the “JPE Companies”) is or was engaged (or was actively considering or contemplating engaging in) at the time of the Employee’s termination, was engaged within the 12 month period prior to the time of Employee’s termination

NOW THEREFORE, based upon the above, the Company agrees to employ the Employee and the Employee agrees to be employed by the Company in accordance with the following terms and conditions.

1.Prior Agreements.  Effective as of the date hereof, this Agreement shall supersede all prior agreements between the Employee and the Company regarding the terms and conditions of Employee’s employment and severance rights with the Company and the JPE Companies including, without limitation any employment agreement or offer letter previously entered into between the Employee and any JPE Company.  Notwithstanding the foregoing, the grant, vesting and other terms and conditions of the Employee’s equity awards shall continue to and will be governed exclusively by the Award Agreements.

2.Term.  This Agreement shall become effective as of the date hereof (the “Effective Date”) and, subject to the provisions of Section 7 below, shall have a term that continues through and including the thirty-six (36) month anniversary of the Effective Date (the “Initial Term”) unless earlier terminated in accordance with this Agreement. Notwithstanding the foregoing, the Employee’s employment with the Company may be terminated prior to the expiration of the Initial Term or any Extension Term in accordance with Section 7 of this Agreement. 

3.Employment After the Term.  Upon and following any non-extension of the Term in accordance with Section 2, the Company and the Employee expect that the Employee will continue to be employed by the Company after the Term on an at-will basis on such terms and conditions as the Company and the Employee may then agree, provided that Sections 9 through 21 of this Agreement shall survive the expiration of the Term, regardless of whether the other provisions of this Agreement remain in effect, subject to the terms thereof, and regardless of whether any termination of the Employee’s employment is effected pursuant to this Agreement. 

4.Duties and Responsibilities.  During the Term of this Agreement, the Employee shall serve as Vice President, Chief Accounting Officer and Controller of the Company.  The Employee shall have those responsibilities ordinarily consistent with his position and those other responsibilities that may be assigned to him from time to time by the Chief Financial Officer.  The Employee agrees to devote his full business time, energy and ability to the performance of his duties and responsibilities under this Agreement, and shall not pursue any other business activity

of any type that would materially interfere with his performance of his duties under this Agreement. 

5.Place of Employment.  The Employee shall perform his duties and responsibilities under this Agreement at the Company’s offices at 600 E. Las Colinas Blvd., Suite 2000, Irving, Texas 75039or, subject to Section 7.E. hereof, such other location(s) as may be required by the Chief Financial officer.

6.Compensation and Benefits and Related Matters.  The Company shall pay the following compensation and benefits to the Employee for all services rendered by the Employee under the Agreement:

A.Base Salary.  Subject to the terms and conditions set forth herein, including Section 7, the Company will pay the Employee a base salary at the annual rate of $300,000 (prorated for any portion of a year in which the Employee is employed by the Company), which amount shall be paid in equal installments on a bi-weekly basis at the Company’s regular payroll intervals.  The Employee’s base salary may be reviewed and adjusted from time to time in the discretion of the Board or the compensation committee of the Board (the “Committee”).

B.Bonus.  The Employee shall be eligible to receive an annual bonus in accordance with the Company’s employee incentive bonus plan, as approved by the Board or the Committee and in effect from time to time.  The Employee shall have a target bonus equal to 50% of the Employee’s annual base salary(“Target Bonus”), which target bonus shall be earned based on the attainment of personal and Company performance goals as established by the Chief Financial Officer or the Committee in its sole discretion.  Notwithstanding the foregoing, the Employee’s receipt of any annual bonus shall be conditioned upon the Company achieving at least 90% of the applicable EBITDA or other performance targets as determined by the Board or the Committee and as necessary to fund such bonus;  provided, however, that the Employee’s bonus for the 2015 fiscal year shall be guaranteed to equal 50% of the Employee’s annual base salary.  The Employee’s right to receive any annual bonus shall be subject to his continued employment with the Company through the applicable date of payment, unless otherwise determined by the Board or the Committee in its discretion or as otherwise set forth in the Company’s employee incentive bonus plan, as in effect from time to time.

C.Benefits. The Employee shall be eligible to participate in all vacation, group health, dental, life, 401(k), profit sharing and other insurance and/or benefit plans that the Company may offer to its employees from time to time and on the same terms as offered to other similarly situated employees as in effect on and after the Effective Date.

D.Business Expenses. During the Term, the Company shall reimburse the Employee for all necessary and reasonable business expenses actually incurred by the Employee for travel, lodging and food in performing his duties and responsibilities under this Agreement in accordance with the Company’s expense reimbursement policies in effect from time to time, provided that the Employee shall submit documentation of such expenses in a form acceptable to the Company.

7.Termination.  The Company and the Employee shall be free to terminate this Agreement and the Employee’s employment hereunder as follows:

A.Termination by the Company for Cause.  The Company shall have the right to terminate for “Cause” immediately.  For purposes of this Agreement, “Cause” shall mean (i) fraud, embezzlement, or theft against the Company or any of its affiliates, (ii) any material violation of the Company’s corporate policies or code of ethics, (iii) any acts involving gross negligence, moral turpitude, dishonesty or fraud, or that in the good faith opinion of the Company may cause a material harm to the Company or any of its affiliates, (iv) an unauthorized disclosure or misuse of any trade secrets or confidential information of the Company or any of its affiliates, (v) material nonperformance by the Employee of his duties hereunder, including, without limitation, failing in any material respect to carry out lawful directions of the Board, and failure to remedy such nonperformance within ten (10) days following written notice from the Company specifically identifying the nonperformance and the actions required to cure it, provided that the Employee shall not be permitted to cure repeated failures, (vi) willful misconduct by the Employee that is intended to, or reasonably likely to, in the good faith judgment of the Company, materially injure the business, prospects, or reputation of the Company or its affiliates and failure to remedy such misconduct within ten (10) days following written notice from the Company specifically identifying the misconduct and the actions required to cure it

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(if such misconduct can be cured), provided that the Employee shall not be permitted to cure repeated failures, (vii) breach of a fiduciary duty owed to the Company or any of the material terms or provisions of this Agreement and failure to remedy such breach within ten (10) days following written notice from the Company specifically identifying the breach and the actions required to cure it (if such breach can be cured), provided that the Employee shall not be permitted to cure repeated failures, (viii) use of illegal drugs at work; and (ix) material breach of the terms of this Agreement.  Notwithstanding any other provision of this Agreement, in the event of a termination pursuant to this Section, the Company shall only be obligated to pay the Employee within thirty (30) days after the date of Employee’s termination of employment (a) his base salary through the date of termination, (b) reimbursement for reimbursable business expenses incurred prior to the date of termination, and (c) such other benefits and payments to which the Employee may be entitled by law or pursuant to the benefit plans of the Company then in effect (the amounts described in clauses (a)-(c), the “Accrued Obligations”).  Notwithstanding the foregoing, any payment to which the Employee may be entitled pursuant to the benefit plans of the Company then in effect shall be paid at the time and in the form specified in such benefit plans.  For the avoidance of doubt, in the event of a termination under this Section 7.A., the Employee shall not be entitled to any other payments under this Agreement except as set forth in the immediately preceding sentence.

B.Disability.  The Company shall have the right to terminate in the event that the Employee shall be prevented by Disability from substantially performing his duties and responsibilities hereunder for ninety (90) or more days out of any one hundred eighty (180) day period.  For purposes of this Agreement, “Disability” shall mean, at any time the Company or any of its affiliates sponsors a long-term disability plan for the Company’s employees, “disability” as defined in such long-term disability plan for the purpose of determining a participant’s eligibility for benefits, provided, however, if the long-term disability plan contains multiple definitions of disability, “Disability” shall refer to that definition of disability which, if the Employee qualified for such disability benefits, would provide coverage for the longest period of time.  The determination of whether the Employee has a Disability shall be made by a physician selected by the Company and reasonably acceptable to the Executive or his representative(s).  At any time the Company does not sponsor a long-term disability plan for its employees, Disability shall mean the Employee’s inability to perform, with or without reasonable accommodation, the essential functions of the Employee’s position for ninety (90) or more days out of any one hundred eighty (180) day period as a result of incapacity due to mental or physical illness as determined by the Board or the Committee in its sole discretion.  Any refusal by the Employee to submit to a medical examination for the purpose of determining Disability shall be deemed to constitute conclusive evidence of the Employee’s Disability. In the event of a termination pursuant to this Section, the Company shall pay the Employee, as severance pay, on the 30th day following termination of employment, an amount equal to his base salary that would have been paid through the end of the third month following the termination, after which time the Employee’s right (if any) to receive income continuation shall be determined solely in accordance with the terms and conditions of the Company’s disability plans and/or any other compensation and benefit plans then in effect.  For the avoidance of doubt, in the event of a termination under this Section 7.B., the Employee shall not be entitled to any other payments under this Agreement except for the Accrued Obligations or as set forth in the immediately preceding sentence.

C.Death.  In the event of a termination by reason of the Employee’s death, the Company shall pay to the Employee’s estate, designated beneficiary or legal representative his base salary through the end of the month in which his death occurs.  For the avoidance of doubt, in the event of a termination under this Section 7.C., the Employee shall not be entitled to any other payments under this Agreement except for the Accrued Obligations or as set forth in the immediately preceding sentence.

D.Termination by the Company other than for Disability, Death or Cause.  The Company shall have the right to terminate, other than for Cause, disability or death, upon thirty (30) days prior written notice to the Employee (or may terminate immediately and pay the Employee’s base salary for such 30 days in a lump sum on the 30th day following termination, subject to Employee’s execution and nonrevocation of a release of claims as described below).  In the event of a termination pursuant to this Section, in addition to any other payments or benefits to which the Employee may be entitled under the Company’s benefit plans then in effect, the Company shall pay to the Employee, (i) his base salary through the date of termination, and (ii) provided that the Employee executes within 21 days after termination of employment and does not revoke a general release of claims against the Company and its affiliates, equityholders, officers, directors, agents and employees as to employment, benefits and compensation related claims, in a form acceptable to the Company, an amount (the “Severance Amount”) equal to one times (1.0x)

3

the sum of Employee’s annual base salary as of the date of termination, payable in a single lump sum within 30 days after the date of termination.  In the event a severance payment is made under this Section 7.D, the Company will pay to Employee a monthly payment on the first payroll date of each month equal to the COBRA cost of continued health and dental coverage under health and dental plans of the Company pursuant to Section 4980B of the Internal Revenue Code, less the amount that Employee would be required to contribute for health and dental coverage if Employee were an active employee, for a period of twelve (12) months from the termination date; provided, however, that this obligation shall cease upon Employee’s obtaining new employment that provides Employee with eligibility for medical benefits without a pre-existing condition limitation (such period is referred to as the “Benefit Period”).  These payments will commence on the Company’s first payroll date after the termination date and will continue until the end of the Benefit Period. For the avoidance of doubt, in the event of a termination under this Section 7.D., the Employee shall not be entitled to any other payments under this Agreement except for the Accrued Obligations or as set forth in the immediately preceding sentence.  For the avoidance of doubt, an election by the Company not to renew the Term effected by the Company giving the Executive written notice of non-extension  of the Term no later than sixty (60) days prior to the expiration of the then-applicable Term in accordance with Section 2 shall not entitle the Executive to the severance payments and benefits described in this subsection D, provided, however, that if the Company terminates the Executive’s employment other than for Cause, disability or death upon the expiration of the Term, the Executive shall be entitled to receive the severance payments and benefits described in this subsection D, subject to all of the terms and conditions described herein. 

E.Termination by the Employee for Good Reason.  The Employee shall have the right to terminate for “Good Reason” upon thirty (30) days’ prior written notice.  For purposes of this Agreement, “Good Reason” shall mean (i) the Company’s material breach of its obligations under this Agreement, including, without limitation, its obligation to pay salary to the Employee, (ii) a material and adverse diminution in the Employee’s job duties, responsibilities or authority, (iii) a change in the location where the Employee is required to perform his duties and responsibilities which exceeds fifty (50) miles from the location specified in Section 5 hereof, or (iv) a material reduction in the Employee’s base salary, it being intended that an individual or aggregate reduction of more than 10% from the Employee’s prior base salary level shall be considered material for purposes of this Agreement.  Employee may not resign Employee’s employment for Good Reason unless (A) Employee gives the Company written notice of his objection to any event set forth above within 30 days following such event, (B) such event is not corrected, in all material respects, by the Company within 30 days following its receipt of such notice, and (C) Employee resigns his employment with the Company not more than 30 days following the expiration of the 30-day correction period described in the foregoing subclause (B).  In the event of a termination pursuant to this Section, in addition to any other payments or benefits to which the Employee may be entitled under the Company’s benefit plans then in effect, the Company shall pay to the Employee, (i) his base salary through the date of termination, and (ii) provided that the Employee executes within 21 days after termination of employment and does not revoke a general release of claims against the Company and its affiliates, equityholders officers, directors, agents and employees as to employment, benefits and compensation related claims, in a form acceptable to the Company, an amount equal to one times (1.0x) the sum of Employee’s base salary as of the date of termination, payable in a single lump sum within 30 days after the date of termination.  In the event a severance payment is made under this Section 7.E., the Company will pay to Employee a monthly payment on the first payroll date of each month equal to the COBRA cost of continued health and dental coverage under health and dental plans of the Company pursuant to Section 4980B of the Internal Revenue Code, less the amount that Employee would be required to contribute for health and dental coverage if Employee were an active employee, for a period of twelve (12) months from the termination date; provided, however, that this obligation shall cease at the end of the Benefits Period.  These payments will commence on the Company’s first payroll date after the termination date and will continue until the end of the Benefit Period. For the avoidance of doubt, in the event of a termination under this Section 7.E., the Employee shall not be entitled to any other payments under this Agreement except for the Accrued Obligations or as set forth in the immediately preceding sentence. 

F.Termination by the Employee other than for Good Reason.  The Employee shall have the right to terminate for any reason other than for Good Reason by providing thirty (30) days’ prior written notice to the Company; provided that the Company may then terminate the Employee immediately.  For the avoidance of doubt, in the event of a termination under this Section 7.F., the Employee shall not be entitled to any other payments under this Agreement except for the Accrued Obligations.

8.Deemed Resignation.  Any termination of the Employee’s employment with the Company shall constitute an automatic resignation of the Employee as an officer of the Company and each JPE Company and an

4

automatic resignation of the Employee from the Board (if applicable, and unless otherwise agreed in writing) and from the board of directors or similar governing body of any JPE Company and from the board of directors or similar governing body of any corporation, limited liability company or other entity in which the Company or any JPE Company holds an equity interest and with respect to which board or similar governing body the Employee serves as the Company’s or such JPE Company’s designee or other representative.

9.Restrictive Covenants and Intellectual Property. 

A.Confidential Information. For the purpose of assisting the Employee in performance of his job requirements and responsibilities with the Company, the Company shall provide the Employee, during the Term of this Agreement, with some or all of the following, any and all of which constitute confidential information of the Company, the Partnership and their respective affiliates, including, but not limited to, JP Energy Development GP LLC and JP Energy Development LP (collectively the “Confidential Information”): (a) any and all trade secrets concerning the business and affairs of the Company, the Partnership or their respective affiliates, product specifications, data, know-how, formulae, compositions, processes, designs, sketches, photographs, graphs, drawings, samples, inventions and ideas, past, current and planned research and development, current and planned manufacturing and distribution methods and processes, customer lists, current and anticipated customer requirements, price lists, market studies, business plans, proprietary technologies, systems, structures, architectures, processes, improvements, devices, know-how, discoveries, concepts, methods and information of the Company, the Partnership and their respective affiliates and any other information, however documented, of the Company, the Partnership and their respective affiliates that is a trade secret under applicable law; (b) any and all information concerning the business and affairs of the Company, the Partnership and their respective affiliates (which includes historical financial statements, financial projections and budgets, historical and projected sales, capital spending budgets and plans, the names and backgrounds of key personnel, contractors, agents, suppliers personnel training and techniques and materials, and purchasing methods and techniques) however documented; and (c) any and all notes, analysis, compilations, studies, summaries and other material prepared by or for the Company, the Partnership and their respective affiliates containing or based, in whole or in part, upon any information included in the foregoing. The Employee acknowledges that he will occupy a position of trust and confidence with the Company during the Term of this Agreement and that he will during the Term of this Agreement have access to and become familiar with such Confidential Information.

Both during and after termination of employment, whether such termination is voluntary or involuntary, the Employee hereby agrees not to disclose to any unauthorized Persons or use for his own account or for the benefit of any third party any Confidential Information, whether or not such information is embodied in writing or other physical form or is retained in the memory of the Employee, without the Company’s prior written consent, unless and to the extent that the Confidential Information was known to Employee prior to his commencement of employment with the Company or is or becomes generally known to and available for use by the public other than as a result of any action by the Employee.  Notwithstanding the foregoing, if the Employee becomes legally compelled to disclose Confidential Information pursuant to judicial or administrative subpoena or process or other legal obligation, the Employee may make such disclosure only to the extent so required.  The Employee will, as promptly as possible and in any event (if permitted by law) prior to the making of such disclosure, notify the Company of any such subpoena, process or obligation and shall cooperate with the Company in seeking a protective order or other means of protecting the confidentiality of the Confidential Information.

The Employee agrees to deliver to the Company at the time his employment under this Agreement terminates for any reason, and at any other time the Company may request, all documents, memoranda, notes, plans, records, reports and other documentation (and all copies of all of the foregoing), that contain Confidential Information and any other Confidential Information that the Employee may then possess or have under his control in transferable form.

B.Noncompetition.  For the period during which the Employee is employed with the Company or its affiliates and during the Restricted Period, the Employee shall not, without the prior written consent of the Company, for whatever reason and with or without cause, either individually or in partnership or jointly or in conjunction with any person or persons as principal, agent, employee, stockholder, consultant, programmer, owner, investor, partner or in any other manner whatsoever (other than a holding of shares listed on a United States stock exchange or automated quotation system that does not exceed five percent of the outstanding shares so listed), directly or indirectly, knowingly (a) engage in the Business or participate in competition with any of the JPE Companies in

5

any state in which (and otherwise within 60 miles of any location where) any JPE Company engages in the Business or is actively considering engaging in the Business (which geographic area shall be determined as of the date of the Employee’s termination with respect to the application of this Section 9.B. following such termination date), (b) solicit such Business from, or provide such services to, any of the customers or accounts of the Company or any of its affiliates or subsidiaries or any JPE Company, or (c) become the employee of, or otherwise render services to or on behalf of, any enterprise which competes with the Business.  For purposes of this Agreement, “Restricted Period” means (1) year following Employee’s termination of employment for any reason, regardless of whether such termination occurs during the Term. 

C.Nonsolicitation.  For the period during which the Employee is employed with the Company or its affiliates pursuant to this Agreement and for two (2) years following Employee’s termination, the Employee shall not, without the prior written consent of the Company, directly or indirectly, knowingly (a) induce or attempt to induce any employee or consultant of any of the JPE Companies to leave the employ or services of any of the JPE Companies, (b) in any way interfere with the relationship between any of the JPE Companies and any employee or consultant of any of the JPE Companies, (c) employ, or otherwise engage as an employee, independent contractor or otherwise, any employee of any of the JPE Companies, or (d) induce or attempt to induce any customer, supplier, licensee or business relation of any of the JPE Companies or its affiliates to cease doing business with any of the JPE Companies, or in any way interfere with the relationship between any customer, supplier, licensee or business relation of any of the JPE Companies. 

D.Non-Disparagement.  The Employee agrees that he will not during the Term of this Agreement or thereafter disparage the Company, the Partnership or any of their respective affiliates, any of the products, practices or services of the Company, the Partnership or any of their respective affiliates, or any directors, officers, managers, employees, agents, representatives, equityholders or affiliates of the Company or the Partnership, either orally or in writing, at any time and the Company shall instruct members of the Board and the executive officers of the Company not to disparage the Employee, either orally or in writing, at any time; provided, that either party may confer in confidence with its legal representatives and make truthful statements as required by law or as required by any applicable rules of professional conduct. 

E. Enforcement. The Employee acknowledges that (a) the Business of the Company and its affiliates is national in scope and may expand over time; (b) its products and services related to such Business are marketed throughout the United States; (c) the Business of the JPE Companies competes with other businesses that are located throughout the United States; (d) the provisions of this Section 9 are reasonable and necessary to protect and preserve the Company’s good will and Confidential Information; (e) this Section 9 is reasonable with respect to its duration, geographical area and scope; (f) the terms of this Section 9 are necessary to safeguard the Company’s Confidential Information; and (g) the Company would be irreparably damaged if the Employee were to breach this Section 9.  In the event of a breach by the Employee of any covenant set forth in this Section 9, the term of such covenant with respect to the Employee will be extended by the period of the duration of such breach. 

The parties hereto agree that, if any court of competent jurisdiction in a final nonappealable judgment determines that a specified time period, a specified geographical area, a specified business limitation or any other relevant feature of this Section 9 is unreasonable, arbitrary or against public policy, then a lesser time period, geographical area, business limitation or other relevant feature which is determined to be reasonable, not arbitrary and not against public policy may be enforced against the applicable party.

The Employee agrees that irreparable damage might occur and that the Company might not have any adequate remedy at law in the event that any of the provisions of this Section 9 were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the Company shall be entitled to seek an injunction or injunctions to prevent breaches of this Section 9 and to seek to enforce specifically the terms and provisions of this Section 9 in any Federal court located in the State of Texas or in any Texas state court, this being in addition to any other remedy to which the Company is entitled at law or in equity.  In addition, each of the parties hereto (a) consents to submit itself to the personal jurisdiction of any Federal court located in the State of Texas or a Texas state court in the event that any dispute arises out of this Section 9 for which an injunction is sought and (b) agrees that it will not attempt to deny or defeat such personal jurisdiction by motion or other request for leave from any such court.  The Employee acknowledges that should it become necessary for the Company to file suit to seek an

6

injunction or other equitable remedy to enforce the provisions contained in this Section 9, and any court of competent jurisdiction awards the Company any damages and/or an injunction due to the acts of the Employee, then the Company shall be entitled to recover its reasonable costs incurred in conducting the suit, including, but not limited to, reasonable attorneys’ fees and expenses.

The Employee further agrees that in the event any of the provisions of this Section 9 are not performed in accordance with their terms or are otherwise breached, the Employee shall forfeit all rights to future payments under this Agreement and shall return to the Company any payments previously made by the Company pursuant to Section 7.D or 7.E of this Agreement.

F.Intellectual Property.  All rights to developments, discoveries, inventions, improvements and innovations (including all data and records pertaining thereto) related to the Business of the Company, whether or not patentable, copyrightable, registrable as a trademark, or reduced to writing, that Employee may develop, discover, invent or originate during Employee’s employment with the Company, either alone or with others and whether or not during working hours or by the use of the facilities of the Company (“Intellectual Property”), shall be the exclusive property of the Company.  Employee shall promptly disclose all Intellectual Property to the Company, shall execute at the request of the Company any assignments or other documents the Company may deem reasonably necessary to protect or perfect its rights therein, and shall assist the Company, upon reasonable request and at the Company’s expense, in obtaining, defending and enforcing the Company’s rights therein. Employee hereby appoints the Company as Employee’s attorney-in‑fact to execute on Employee’s behalf any assignments or other documents reasonably deemed necessary by the Company to protect or perfect its rights to any Intellectual Property.

10.Duty of Loyalty.  The Employee acknowledges that he is a fiduciary of the Company and owes a duty of loyalty to the Company to perform his duties and responsibilities under this Agreement in good faith and in the best interests of the Company and without personal economic conflict.

11.Assignment.  This Agreement, and the rights and obligations of the Employee and the Company hereunder, shall inure to the benefit of and shall be binding upon the Employee, his heirs and representatives, and upon the Company and its successors and assigns.  This Agreement may not be assigned by either party, except that the Company may assign this Agreement to any affiliate of or successor to the Company. 

12.Choice of Law; Venue; Waiver of Jury Trial.  This Agreement shall be construed and interpreted in accordance with, and all disputes arising under or related to this Agreement shall be governed by, the laws of the State of Texas.  Each party to this Agreement hereby consents to the exclusive jurisdiction and venue of the United States District Court located in Dallas, Texas and of the State courts located in Dallas, Texas and irrevocably agrees that all actions or proceedings arising out of or relating to this Agreement shall be litigated in such courts.  Each party (a) consents to submit himself, herself or itself to the personal jurisdiction of such courts for such actions or proceedings, (b) agrees that he, she or it will not attempt to deny or defeat such personal jurisdiction by motion or other request for leave from any such court, and (c) agrees that he, she or it will not bring any such action or proceeding in any court other than such courts.  Each party accepts for himself, herself or itself and in connection with such party’s properties, generally and unconditionally, the exclusive and irrevocable jurisdiction and venue of the aforesaid courts and waives any defense of forum non conveniens, and irrevocably agrees to be bound by any non-appealable judgment rendered thereby in connection with such actions or proceedings.  A copy of any service of process served upon the parties shall be mailed by registered mail to the respective party except that, unless otherwise provided by applicable law, any failure to mail such copy shall not affect the validity of service of process.  If any agent appointed by a party refuses to accept service, each party agrees that service upon the appropriate party by registered mail shall constitute sufficient service.  Nothing herein shall affect the right of a party to serve process in any other manner permitted by law.  Because disputes arising in connection with an employment relationship of the type set forth in this Agreement are most quickly and economically resolved by an experienced and expert person, the parties desire that their disputes be resolved by a judge applying all applicable laws as set forth herein. Therefore, each party to this Agreement hereby waives all rights to trial by jury in any action, suit, or proceeding brought to resolve any dispute between the parties hereto, whether arising in contract, tort, or otherwise, arising out of, connected with, related or incidental to this Agreement, the transactions contemplated hereby and/or the relationship established between the parties hereunder.

7

13.Notices.  All notices required by this Agreement shall be in writing and shall be delivered in person or mailed by certified mail, return receipt requested, or by a nationally recognized overnight delivery service as follows:

A.If to the Employee:

At the address set forth under the Employee’s signature to this Agreement

B.If to the Company:

JP Energy GP II LLC

600 E. Las Colinas Blvd, Suite 2000

Irving, Texas 75039

Attn: Legal

Fax:  972-444-0320

or to such other address as the Employee or the Company, as applicable, shall specify in writing given in accordance with this Section 13.

14.Severability.  In the event that any one or more of the provisions of this Agreement shall be held to be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.  Moreover, if any one or more of the provisions contained in this Agreement shall be held to be excessively broad as to duration, activity or subject, such provision shall be construed by limiting or reducing them so as to be enforceable to the maximum extent compatible with applicable law.

15.Waiver.  No consent to or waiver of any breach or default in the performance of any obligation hereunder shall be deemed or construed to be a consent to or waiver of any other breach or default in the performance of any of the same or any other obligations hereunder.  No purported waiver hereunder shall be effective unless it is in writing and signed by the party waiving the breach or default hereunder.

16.Entire Agreement; Modification.  This Agreement sets forth the entire agreement and understanding between the Employee and the Company with respect to the subject matter contained herein, and supersedes any employment agreement or offer letter previously entered into between the Employee and any JPE Company and all other prior agreements, arrangements and understandings between them, whether written or oral, relating to the subject matter hereof.  Notwithstanding the foregoing, the Award Agreement(s), if any, previously entered into by the Employee shall remain unchanged by this Agreement and shall continue in full force and effect according to their terms.  This Agreement may be amended only by a written instrument signed by the Employee and an authorized representative of the Company.

17.Headings.  The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement.

18.Counterparts.  This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which taken together shall constitute one and the same agreement, and shall become effective when one or more counterparts have been signed by the Employee and the Company.

19.Consultation with Counsel; No Representations.  The Employee agrees and acknowledges that he has had a full and complete opportunity to consult with counsel of his own choosing concerning the terms, enforceability and implications of this Agreement, and that the Company has made no representations, warranties, promises or inducements to him concerning the terms, enforceability or implications of this Agreement other than are as reflected in this Agreement.

20.Withholding.  The Company shall be entitled to withhold from any amounts payable under this Agreement any federal, state, local or foreign withholding or other taxes or charges which the Company is required to

8

withhold. The Company shall be entitled to rely on an opinion of counsel if any questions as to the amount or requirement of withholding shall arise.

21.Defense of Claims.  Employee agrees that, during a period of 48 months after the date on which Employee’s employment with the Company ceases, Employee will, upon written request by the Company, cooperate with the Company in the defense of any claims or actions that may be made by or against the Company or its affiliates that relate to Employee’s prior areas of responsibility, except if Employee’s reasonable interests are adverse to such entities in such claim or action.  The Company agrees to pay or reimburse Employee for all of his reasonable travel and other direct expenses incurred, or to be reasonably incurred, to comply with Employee’s obligations under this Section. 

22.409A Compliance.  The intent of the Parties is that the payments and benefits under this Agreement comply with or be exempt from Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgated thereunder (collectively, “Section 409A”) and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to be in compliance therewith.

Notwithstanding anything in this Agreement to the contrary, any compensation or benefits payable under this Agreement that is designated under this Agreement as payable upon Employee’s termination of employment shall be payable only upon Employee’s “separation from service” with the Company within the meaning of Section 409A (a “Separation from Service”).

Notwithstanding anything in this Agreement to the contrary, if Employee is deemed by the Company at the time of Employee’s Separation from Service to be a “specified employee” for purposes of Section 409A, to the extent delayed commencement of any portion of the benefits to which Employee is entitled under this Agreement is required in order to avoid a prohibited distribution under Section 409A, such portion of Employee’s benefits shall not be provided to Employee prior to the earlier of (i) the expiration of the six-month period measured from the date of Employee’s Separation from Service with the Company or (ii) the date of Employee’s death.  Upon the first business day following the expiration of the applicable Section 409A period, all payments deferred pursuant to the preceding sentence shall be paid in a lump sum to Employee (or Employee’s estate or beneficiaries), and any remaining payments due to Employee under this Agreement shall be paid as otherwise provided herein.

To the extent that any reimbursements under this Agreement are subject to Section 409A, any such reimbursements payable to Employee shall be paid to Employee no later than December 31 of the year following the year in which the expense was incurred.  Provided that Employee submits Employee’s reimbursement request promptly following the date the expense is incurred, the amount of expenses reimbursed in one year shall not affect the amount eligible for reimbursement in any subsequent year, other than medical expenses referred to in Section 105(b) of the Code, and Employee’s right to reimbursement under this Agreement will not be subject to liquidation or exchange for another benefit.

Employee’s right to receive any installment payments under this Agreement, including without limitation any continuation salary payments that are payable on Company payroll dates, shall be treated as a right to receive a series of separate payments and, accordingly, each such installment payment shall at all times be considered a separate and distinct payment as permitted under Section 409A.  Except as otherwise permitted under Section 409A, no payment hereunder shall be accelerated or deferred unless such acceleration or deferral would not result in additional tax or interest pursuant to Section 409A.

[Signature page follows]

9

IN WITNESS WHEREOF, the undersigned have caused this Agreement to be executed and delivered as of the date first written above.

JP ENERGY GP II LLC
By:	/s/ Patrick Welch
	Name:	Patrick Welch
	Title:	EVP and CFO
EMPLOYEE
By:	/s/ Simon Chen
	Name:	Simon Chen
	Address:	4005 Wycliff Avenue
		Dallas, TX 75219

EX-21.1

Exhibit 21.1

Subsidiaries of JP Energy Partners LP

	Jurisdiction of
Entity	Formation
Alliant Arizona Propane, L.L.C.	Delaware
Alliant Gas, LLC	Texas
JP Energy ATT, LLC	Delaware
JP Energy Caddo, LLC	Delaware
JP Energy Crude Oil Services, LLC	Delaware
JP Energy Permian, LLC	Delaware
JP Energy Products Supply, LLC	Delaware
JP Energy Refined Products, LLC	Delaware
JP Energy Services, LLC	Delaware
JP Energy St. Croix, LLC	Delaware
JP Energy Storage, LLC	Oklahoma
JP Falco, LLC	Delaware
JP Liquids, LLC	Delaware
Pinnacle Propane Express, LLC	Delaware
Pinnacle Propane, LLC	Texas

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S‑8 (No. 333-200074) of JP Energy Partners LP of our report dated February 29, 2016 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 29, 2016

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rules 13a-14 and 15d-14 Under the Securities Exchange Act of 1934

I, J. Patrick Barley, certify that:

1. I have reviewed this annual report on Form 10-K (this “report”) of JP Energy Partners LP (the “registrant”);

2. based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. the registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. the registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2016	/s/ J. Patrick Barley
	J. Patrick Barley
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rules 13a-14 and 15d-14 Under the Securities Exchange Act of 1934

I, Patrick J. Welch, certify that:

1. I have reviewed this annual report on Form 10-K (this “report”) of JP Energy Partners LP (the “registrant”);

2. based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. the registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. the registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2016	/s/ Patrick J. Welch
	Patrick J. Welch
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code),I, J. Patrick Barley, President and Chief Executive Officer of JP Energy GP II LLC, as general partner of JP Energy Partners LP (the “Partnership”), hereby certify, to the best of my knowledge, that:

(1) the Partnership’s Annual Report on Form 10-K for the period ended December 31, 2015 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

eb
Date: February 29, 2016	/s/ J. Patrick Barley
	Name:	J. Patrick Barley
	Title:	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section906 of the Sarbanes-Oxley Act of 2002

(Subsections (a)and (b)of Section1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code),I, Patrick J. Welch, Executive Vice President and Chief Financial Officer of JP Energy GP II LLC, as general partner of JP Energy Partners LP (the “Partnership”), hereby certify, to the best of my knowledge, that:

(1) the Partnership’s Annual Report on Form 10-K for the period ended December 31, 2015 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 29, 2016	/s/ Patrick J. Welch
	Name:	Patrick J. Welch
	Title:	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Entity Registrant Name	JP Energy Partners LP
Entity Central Index Key	0001523404
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 187,527,418
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Common
Entity Common Stock, Shares Outstanding		18,467,032
Subordinated
Entity Common Stock, Shares Outstanding		18,126,511

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 1,987	$ 3,325
Restricted cash		600
Accounts receivable, net	60,519	108,725
Receivables from related parties	8,624	10,548
Inventory	4,786	5,677
Prepaid expenses and other current assets	4,168	4,915
Current assets of discontinued operations held for sale	2,730	15,149
Total Current Assets	82,814	148,939
Non-current assets
Property, plant and equipment, net	291,454	251,690
Goodwill	216,692	240,782
Intangible assets, net	134,432	145,330
Deferred financing costs and other assets, net	3,223	4,711
Noncurrent assets of discontinued operations held for sale	6,644	21,721
Total Non-Current Assets	652,445	664,234
Total Assets	735,259	813,173
Current liabilities
Accounts payable	45,933	88,052
Accrued liabilities	15,260	28,971
Capital leases and short-term debt	107	229
Customer deposits and advances	3,742	5,050
Current portion of long-term debt	454	383
Current liabilities of discontinued operations held for sale	640
Total Current Liabilities	66,136	122,685
Non-current liabilities
Long-term debt	162,740	84,125
Other long-term liabilities	1,463	5,683
Total Liabilities	$ 230,339	$ 212,493
Commitments and Contingencies
Partners' capital
General partner	$ 5,568
Common units (22,119,170 and 21,852,219 units authorized as of December 31, 2015 and 2014, respectively; 18,465,320 and 18,209,519 units issued and outstanding as of December 31, 2015 and 2014, respectively)	266,691	$ 315,630
Subordinated units (18,197,249 units authorized; 18,127,678 and 18,197,249 units issued and outstanding as of December 31, 2015 and 2014, respectively)	232,661	285,050
Total Partners' Capital	504,920	600,680
Total Liabilities and Partners' Capital	$ 735,259	$ 813,173

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
Common units, units authorized	22,119,170	21,852,219
Common units, units issued	18,465,320	18,209,519
Common units, units outstanding	18,465,320	18,209,519
Subordinated units, units authorized	18,197,249	18,197,249
Subordinated units, units issued	18,127,678	18,197,249
Subordinated units, units outstanding	18,127,678	18,197,249

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES
Crude oil sales	$ 455,465,000	$ 470,336,000	$ 164,356,000
Crude oil sales - related parties	884,000
Gathering, transportation and storage fees	25,991,000	30,762,000	23,942,000
Gathering, transportation and storage fees - related parties	2,165,000
NGL and refined product sales	170,009,000	192,804,000	166,245,000
NGL and refined product sales - related parties		7,419,000	12,343,000
Refined products terminals and storage fees	12,362,000	10,260,000	10,179,000
Refined products terminals and storage fees - related parties		1,533,000	2,130,000
Other revenues	13,709,000	13,040,000	11,674,000
Total revenues	680,585,000	726,154,000	390,869,000
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization	527,476,000	605,682,000	276,804,000
Operating expense	69,377,000	65,584,000	57,728,000
General and administrative	45,383,000	46,362,000	44,488,000
Depreciation and amortization	46,852,000	40,230,000	30,987,000
Goodwill impairment	29,896,000
Loss on disposal of assets, net	909,000	1,137,000	1,492,000
Total costs and expenses	719,893,000	758,995,000	411,499,000
OPERATING LOSS	(39,308,000)	(32,841,000)	(20,630,000)
OTHER INCOME (EXPENSE)
Interest expense	(5,375,000)	(8,981,000)	(8,245,000)
Loss on extinguishment of debt		(1,634,000)
Other income, net	1,732,000	8,000	887,000
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(42,951,000)	(43,448,000)	(27,988,000)
Income tax expense	(754,000)	(300,000)	(208,000)
LOSS FROM CONTINUING OPERATIONS	(43,705,000)	(43,748,000)	(28,196,000)
DISCONTINUED OPERATIONS
Net income (loss) from discontinued operations, including loss on disposal of $7,288 in 2014	(14,951,000)	(9,275,000)	13,975,000
NET LOSS	(58,656,000)	(53,023,000)	$ (14,221,000)
Net loss attributable to the period from January 1, 2014 to October 1, 2014		34,407,000
Net loss attributable to limited partners	(58,656,000)	(18,616,000)
Basic and diluted loss per unit
Net loss from continuing operations allocated to limited partners	(43,705,000)	(18,950,000)
Net loss allocated to limited partners	$ (58,656,000)	(18,616,000)
Common and Subordinated
Basic and diluted loss per unit
Distribution declared per unit (in dollars per unit)	$ 1.279
Common
DISCONTINUED OPERATIONS
Net loss attributable to limited partners	$ (29,351,000)	(9,293,000)
Basic and diluted loss per unit
Net loss from continuing operations allocated to limited partners	(21,830,000)	(9,460,000)
Net loss allocated to limited partners	$ (29,351,000)	$ (9,293,000)
Weighted average number of common units outstanding (in units)	18,373,594	18,212,632
Basic and diluted net loss from continuing operations (in dollars per unit)	$ (1.19)	$ (0.52)
Basic and diluted net loss (in dollars per unit)	$ (1.60)	$ (0.51)
Subordinated
DISCONTINUED OPERATIONS
Net loss attributable to limited partners	$ (29,305,000)	$ (9,323,000)
Basic and diluted loss per unit
Net loss from continuing operations allocated to limited partners	(21,875,000)	(9,490,000)
Net loss allocated to limited partners	$ (29,305,000)	$ (9,323,000)
Weighted average number of subordinated units outstanding (in units)	18,151,700	18,209,948
Basic and diluted net loss from continuing operations (in dollars per unit)	$ (1.20)	$ (0.52)
Basic and diluted net loss (in dollars per unit)	$ (1.61)	$ (0.51)

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CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)
CONSOLIDATED STATEMENTS OF OPERATIONS
Net income (loss) from discontinued operations, loss on disposal	$ 7,288

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (58,656)	$ (53,023)	$ (14,221)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:
Depreciation and amortization	49,133	43,922	36,195
Goodwill impairment	37,835
Asset Impairment	4,970	1,984
Derivative valuation changes	(11,340)	12,645	(1,162)
Amortization of deferred financing costs	909	906	1,103
Unit-based compensation expenses	1,309	1,789	948
Loss on disposal of assets	1,028	8,415	1,492
Bad debt expense	1,212	820	855
Loss on extinguishment of debt		1,634
Non-cash inventory LCM adjustment		222
Other non-cash items	1,744	434	(378)
Changes in working capital, net of acquired assets and liabilities:
Accounts receivable	47,926	13,307	(26,583)
Receivable from related parties	1,924	(7,806)	(948)
Inventory	13,372	17,501	(18,646)
Prepaid expenses and other current assets	709	(545)	4,340
Accounts payable and other accrued liabilities	(45,168)	(13,078)	30,106
Payables to related parties		(1,464)	1,274
Customer deposits and advances	(1,308)	2,328	(493)
Changes in other assets and liabilities	442	166
NET CASH PROVIDED BY OPERATING ACTIVITIES	46,041	30,157	13,882
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(71,011)	(56,878)	(26,828)
Acquisitions of businesses	(12,583)		(1,003)
Proceeds received from sale of assets	3,917	11,325	96
Change in restricted cash	600	(600)
NET CASH USED IN INVESTING ACTIVITIES	(79,077)	(46,153)	(27,735)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving line of credit	130,000	390,800	32,300
Payments on revolving line of credit	(51,000)	(485,357)	(12,150)
Proceeds from note payable to related party			1,000
Payments on long-term debt	(375)	(4,870)	(4,152)
Payment of related party note payable		(1,000)
Payments on capital leases	(137)	(162)	(164)
Payments on contingent earnout liabilities	(488)
Change in cash overdraft	(91)	(295)	386
Payments on financed insurance premium		(49)	(5,127)
Debt issuance costs	(6)	(3,193)	(980)
Distributions to unitholders	(47,025)	(91,956)	(17,438)
Issuance of Series D preferred units		40,000
Redemption of Series D preferred units		(42,436)
Issuance of common units, net of issuance costs		262,638	3,128
Common control acquisition		(52,000)
Contributions from the Predecessor		4,321	12,040
Contributions from general partner	1,218
Tax withholding on unit-based vesting	(289)	(354)
Other	(109)		(1,855)
NET CASH PROVIDED BY FINANCING ACTIVITIES	31,698	16,087	6,988
Net change in cash and cash equivalents	(1,338)	91	(6,865)
Cash and cash equivalents balance, beginning of period	3,325	3,234	10,099
Cash and cash equivalents balance, end of period	1,987	3,325	3,234
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest	4,527	7,179	7,063
Cash paid for taxes	450	108	106
Non-cash investing and financing transactions:
Accrued capital expenditures	3,796	3,628	977
Debt funded portion of acquisition	12,475	52,000
Acquisitions funded by issuance of units	3,442	267,100
Assets acquired under capital lease		$ 177	13
Financed insurance premium			$ 1,420
Contributions from general partner	$ 4,350

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CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Preferred Series D Preferred Unit	General Partner	Limited Common	Limited Subordinated	Limited Class A Common Unit	Limited Class B Common Unit	Limited Class C Common Unit	Predecessor Capital	Total
Balance at Dec. 31, 2012	$ 20,966	$ 404			$ 144,534	$ 14,247	$ 82,864	$ 51,138	$ 314,153
Balance (in units) at Dec. 31, 2012	1,136,364	45			6,868,004	1,153,505	3,166,667		12,324,585
Increase (Decrease) in Partners' Capital
Contribution from the Predecessor								246,987	$ 246,987
Issuance of Class B Common Units						$ (164)			$ (164)
Issuance of Class B Common Units (in units)						53,339			53,339
Issuance of Class C Common Units							$ 3,128		$ 3,128
Issuance of Class C Common Units (in units)							88,114		88,114
Conversion of units	$ (18,660)				$ 18,660
Conversion of units (in units)	(1,136,364)				1,136,364
Unit-based compensation						$ 948			$ 948
Distributions to unitholders	$ (1,704)				$ (10,085)	(1,683)	$ (3,966)		(17,438)
Net income (loss)	(602)				(12,357)	(1,982)	(5,220)	5,940	(14,221)
Balance at Dec. 31, 2013		$ 404			$ 140,752	$ 11,366	$ 76,806	304,065	$ 533,393
Balance (in units) at Dec. 31, 2013		45			8,004,368	1,206,844	3,254,781		12,466,038
Increase (Decrease) in Partners' Capital
Contribution from the Predecessor								4,321	$ 4,321
Issuance of Class A Common Units					$ 8,000				$ 8,000
Issuance of Class A Common Units (in units)					363,636				363,636
Issuance of Class B Common Units (in units)						90,000			90,000
Issuance of Preferred Units	$ 40,000								$ 40,000
Issuance of Preferred Units (in units)	1,928,909								1,928,909
Redemption of Preferred Units	$ (40,656)		$ (350)	$ (1,430)					$ (42,436)
Redemption of Preferred Units (in units)	(1,928,909)								(1,928,909)
Unit-based compensation			123	503		$ 1,163			$ 1,789
Common control acquisition		$ (12,727)			$ 267,067			(306,340)	$ (52,000)
Common control acquisition (in units)					12,561,934				12,561,934
Recapitalization		$ 12,323	$ 72,405	$ 295,453	$ (313,481)	$ (6,268)	$ (60,432)
Recapitalization (in units)		(45)	4,463,502	18,213,502	(20,929,938)	(1,296,844)	(3,254,781)		(2,804,604)
Issuance of Common Units, net of issuance costs, forfeitures and tax withholdings			$ 252,745						$ 252,745
Issuance of Common Units, net of forfeitures (in units)			13,746,017						13,746,017
Issuance of Subordinated Units, net of issuance costs, forfeitures and tax withholdings				$ (153)					$ (153)
Forfeiture of Subordinated Units (in units)				(16,253)					(16,253)
Distributions to unitholders					$ (75,662)	$ (4,528)	$ (11,766)		$ (91,956)
Net income (loss) | Successor			$ (9,293)	$ (9,323)					(18,616)
Net income (loss) | Predecessor	$ 656				$ (26,676)	$ (1,733)	$ (4,608)	$ (2,046)	(34,407)
Net income (loss)									(53,023)
Balance at Dec. 31, 2014			$ 315,630	$ 285,050					$ 600,680
Balance (in units) at Dec. 31, 2014			18,209,519	18,197,249					36,406,768
Increase (Decrease) in Partners' Capital
Unit-based compensation			$ 941	$ 368					$ 1,309
Issuance of units, net of issuance costs, forfeitures and tax withholdings			$ 3,259	$ (215)					$ 3,044
Issuance of Common Units (in units)			266,951						266,951
Forfeiture of units under LTIP (in units)			(19,400)	(69,571)					(88,971)
Vesting Of units under LTIP (in units)			8,250						8,250
Distributions to unitholders			$ (23,788)	$ (23,237)					$ (47,025)
Contributions from general partner		$ 5,568							5,568
Net income (loss)			(29,351)	(29,305)					(58,656)
Balance at Dec. 31, 2015		$ 5,568	$ 266,691	$ 232,661					$ 504,920
Balance (in units) at Dec. 31, 2015			18,465,320	18,127,678					36,592,998

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Business and Basis of Presentation

12 Months Ended

Dec. 31, 2015

Business and Basis of Presentation

Business and Basis of Presentation

1. Business and Basis of Presentation

Business.  The consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries. All expressions of the “Partnership”, “JPE”, “us”, “we”, “our”, and all similar expressions are references to JP Energy Partners LP and our consolidated, wholly-owned subsidiaries, unless otherwise expressly stated or the context requires otherwise. We were formed in May 2010 by members of management and were further capitalized in June 2011 by ArcLight Capital Partners, LLC (“ArcLight”) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. JP Energy GP II LLC (“GP II”) is our general partner.

JP Development.On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership (“JP Development”), for the express purpose of supporting JPE’s growth. Since its formation, JP Development had acquired a portfolio of midstream assets that were developed for potential future sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development made the following acquisitions since its formation in July 2012:

On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company (“Parnon Gathering”), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition, Parnon Gathering LLC was renamed to JP Energy Marketing LLC (“JPEM”).

On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH Propane, LLC, an Arkansas limited liability company (“BMH”), which is engaged in the retail and wholesale propane and refined fuel distribution business.

On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil Field Services, Inc., a Texas Corporation (“AOFS”), which is engaged in the crude oil trucking business.

On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability company (“Wildcat Permian”) that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company (“JP Permian”).  JP Permian is engaged in the transportation of crude oil by pipeline.

On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development (“JP Liquids”), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation (“Highway Pipeline”), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.

As a result of the sale of its GSPP pipeline assets (see Note 3), JP Development does not currently hold any material assets.

Common Control Acquisition between JPE and JP Development.  On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, we acquired (i) certain marketing and trucking businesses of JPEM (the “Parnon Gathering Assets”), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the “Dropdown Assets”) from JP Development for an aggregate purchase price of approximately $319.1 million (the “Common Control Acquisition”), which was comprised of 12,561,934 JPE Class A Common Units and $52 million cash. We financed the cash portion of the purchase price through borrowings under our revolving credit facility.

Basis of Presentation.  Because JPE and JP Development are under common control, we are required under generally accepted accounting principles in the United States (“GAAP”) to account for this Common Control Acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, our balance sheet reflected JP Development’s historical carryover net basis in the Dropdown Assets instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. We also retrospectively recast our financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).

The historical assets and liabilities and the operating results of the Dropdown Assets have been “carved out” from JP Development’s consolidated financial statements using JP Development’s historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. Our recast historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification.  Management believes the assumptions underlying the combined financial statements are reasonable.  However, the combined financial statements do not fully reflect what our, including the Dropdown Assets’ balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under our management during the periods presented. As a result, historical financial information is not necessarily indicative of what our balance sheet, results of operations, and cash flows will be in the future.

JP Development has a centralized cash management that covers all of its subsidiaries.  The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the years ended December 31, 2014 and 2013.  The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity.  The net balances due to us from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.

The total purchase price from the Common Control Acquisition exceeded JP Development’s book value of the net assets acquired. As a result, the excess of the total purchase price over the book value of the assets acquired of $12.7 million was considered a deemed distribution by the general partner and is included as a reduction in general partner interest in Partners’ Capital.

The “predecessor capital” included in Partners’ Capital represents JP Development’s net investment in the Dropdown Assets, which included the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development.  Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled and, as a result, were considered deemed contributions or distributions and are included in JP Development’s net investment.

Net income (loss) attributable to the Dropdown Assets prior to our acquisition of such assets was not available for distribution to our unitholders. Therefore, this income (loss) was not allocated to the limited partners for the purpose of calculating net loss per common unit; instead, the income (loss) was allocated to predecessor capital.

Initial Public Offering. On October 2, 2014, our common units began trading on the New York Stock Exchange under the ticker symbol “JPEP.” On October 7, 2014, we closed our IPO of 13,750,000 common units at a price of $20.00 per unit.  Prior to the closing of the IPO, the following recapitalization trasactions occurred:

we distributed approximately $92.1 million of accounts receivable that comprised our working capital assets to the existing partners, pro rata in accordance with their ownership interests, of which $72.5 million, $6.0 million and $3.3 million was distributed to Lonestar Midstream Holdings, LLC (“Lonestar”),  Truman Arnold Companies (“TAC”) and JP Development, respectively, all of which are related parties;

each Class A common unit, Class B common unit and Class C common unit (collectively, the “Existing Common Units”) were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and

an aggregate of 18,213,502 Existing Common Units held by the existing partners were automatically converted into 18,213,502 subordinated units representing a 80.3% interest in us prior to the IPO, and a 50.0% interest in us after the closing of the IPO, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the “Remaining Existing Common Units”).

Subsequent to the closing of the IPO, the following recapitalization transactions occurred:

the Remaining Existing Common Units were automatically converted on a one-to-one basis into 4,463,502 common units representing a 12.3% interest in us;

the 45 general partner units in the Partnership held by the general partner were recharacterized as a non-economic general partner interest in us; and

we issued 13,750,000 common units to the public representing a 37.7% interest in us.

We used the proceeds from the IPO of approximately $257.1 million, net of underwriting discounts and structuring fees, to:

pay offering expenses of approximately $2.0 million;

redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4million;

repay $195.6 million of the debt outstanding under our revolving credit facility; and

replenish $17.1 million of working capital that was distributed to the then existing partners immediately prior to the IPO.

Immediately following the repayment of the debt outstanding under the our revolving credit facility, we borrowed approximately $75.0 million thereunder in order to replenish the remainder of working capital that was distributed to existing partners immediately prior to the IPO.

Partnership Agreement. In connection with the IPO, we executed the Third Amended and Restated Agreement of Limited Partnership (“Amended Partnership Agreement”) on October 7, 2014. The Amended Partnership Agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date, subject to certain terms and conditions.  See Note 13 for additional information.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

2.Summary of Significant Accounting Policies

Principles of Consolidation.  Our consolidated financial statements have been prepared in accordance with GAAP. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

Reclassification.  Certain previously reported amounts have been reclassified to conform to the current year presentation. For the years ended December 31, 2014 and 2013, we reclassified $9,911,000 and $1,687,000, respectively, from gathering, transportation and storage fees to crude oil sales to conform to the current year presentation.

Use of Estimates.  The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Cash and Cash Equivalents.  We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Bank overdrafts that do not meet the right of offset criteria are recorded in capital leases and short-term debt in the consolidated balance sheets.

Restricted Cash.  Restricted cash consists of cash balances that are restricted as to withdrawal or usage and at December 31, 2014, included cash to secure crude oil production taxes payable to the applicable taxing authorities.

Accounts Receivable.  Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the consolidated statements of operations. The allowance for doubtful accounts was $1,217,000 and $1,134,000 as of December 31, 2015 and 2014, respectively. Bad debt expense for the years ended December 31, 2015, 2014 and 2013 was $1,212,000,  $820,000 and $855,000, respectively.

Inventory.  Inventory is mainly comprised of crude oil, NGLs, refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. Cost of crude oil, NGLs and refined products inventory is determined using the first-in, first-out (FIFO) method. Cost of propane cylinders is determined using the weighted average method.

Prepaid Expenses and Other Current Assets.  Prepaid expenses and other current assets primarily relate to prepaid insurance premiums, which totaled $1,239,000 and $1,044,000, and insurance claim receivables, which totaled $115,000 and $965,000 as of December 31, 2015 and 2014, respectively.

Derivative Instruments and Hedging Activities.  We recognize all derivative instruments as either assets or liabilities on the balance sheet at their respective fair values. We did not have any derivatives designated in hedging relationships during the years ended December 31, 2015, 2014 and 2013. Therefore, the change in the fair value of the derivative asset or liability is reflected in net loss in the consolidated statements of operations (mark-to-market accounting). Cash flows from derivatives settled are reported as cash flow from operating activities, in the same category as the cash flows from the items being economically hedged.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sales exception (“NPNS”) accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.

Property, Plant and Equipment.  Property, plant and equipment is recorded at historical cost of construction, or, upon acquisition, the fair value of the assets acquired. Repairs and maintenance costs are expensed as incurred. Any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the account, and any resulting gain or loss is recognized within the consolidated statements of operations.

We account for asset retirement obligations by recognizing on our balance sheet the net present value of any legally binding obligation to remove or remediate tangible long-lived assets, such as requirements to dispose of equipment. We record a liability for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:

Buildings	20	-	30	years
Leasehold improvements		Various*
Transportation equipment	5	-	15	years
Propane tanks and cylinders	3	-	25	years
Bulk storage tanks			20	years
Pipelines			20	years
Office furniture and fixtures	5	-	10	years
Other equipment	3	-	31	years

*Depreciated over the shorter of the life of the leasehold improvement or the lease term.

Leases.  We have both capital and operating leases. Classification is made at the inception of the lease. The classification of leases is based on the extent to which risks and rewards incidental to ownership of a leased asset lie with the lessor or the lessee.

Leased property meeting certain capital lease criteria is capitalized and the present value of the related lease payments is recorded as a liability. The present value of the minimum lease payments is calculated utilizing the lower of our incremental borrowing rate or the lessor’s interest rate implicit in the lease, if known by us. Depreciation of capitalized leased assets is computed utilizing the straight-line method over the shorter of the estimated useful life of the asset or the lease term and is included in depreciation and amortization in our consolidated statements of operations. However, if the lease meets the bargain purchase or transfer of ownership criteria, the asset shall be amortized in accordance with our normal depreciation policy for owned assets.

Minimum rent payments under operating leases are recognized as an expense on a straight-line basis over the lease term, including any rent free periods.

Impairment of Long-Lived Assets.  Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3). For assets held for sale, we compare the fair value of the disposal group to its carrying value. Under the assets held for sale criteria, the order of impairment is based on (i) testing other assets, such as accounts receivable, inventory and indefinite-lived intangible assets, for impairment (ii) testing goodwill for impairment and (iii) testing the long-lived asset group for impairment. In connection with the sale of our Mid-Continent Business (defined in Note 3 and classified as held for sale at December 31, 2015), we recorded an impairment charge of $4,970,000 during the year ended December 31, 2015 related to long-lived assets, which is classified in net loss from discontinued operations in the consolidated statements of operations.

Goodwill and Other Intangible Assets.We apply Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill. In accordance with these standards, goodwill is not amortized but is tested for impairment at least annually, or more frequently whenever a triggering event or change in circumstances occurs at the reporting unit level. A reporting unit is the operating segment, or business one level below the operating segment if discrete financial information is prepared and regularly reviewed by segment management. We have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.

In 2015, we recognized impairment charges of $23,574,000 and $6,322,000 related to the goodwill in our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volume in those reporting units.  We also recorded an additional goodwill impairment charge of $7,939,000 triggered by the disposition of our Mid-Continent Business. The $7,939,000 of goodwill was allocated to the Mid-Continent Business based on the relative fair value of the Mid-Continent Business and the portion of the reporting unit that was retained by us. No provision for impairment of goodwill was recorded during 2014 or 2013.

During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the crude oil supply and logistics reporting unit, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by us. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.

Business Combinations.  When a business is acquired, we allocate the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. The accounting standard for business combinations requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs associated with the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt’s stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite. Contingent consideration obligations are recorded at fair value on the date of acquisition, with increases or decreases in the fair value arising from changes in assumptions or discount periods recorded as contingent consideration expenses in the consolidated statement of operations in subsequent periods. The fair values assigned to tangible and intangible assets acquired and liabilities assumed, including contingent consideration, are based on management’s estimates and assumptions, as well as other information compiled by management, including valuations that utilize customary valuation procedures and techniques.

When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting. Under a common control acquisition, the assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

Deferred Financing Costs.  Debt issuance costs related to our revolving credit agreement (see Note 11) are deferred and are recorded net of accumulated amortization in the consolidated balance sheets as deferred financing costs, and totaled $2,809,000 and $3,712,000 at December 31, 2015 and 2014, respectively. These costs are amortized over the terms of the related debt using the effective interest rate method for the notes payable and the straight-line method for the revolving credit facilities. As a result of the financing transactions discussed in Note 11, we wrote off $1,634,000 of deferred financing costs associated with the extinguishment of debt during the year ended December 31, 2014 which is recorded in loss on extinguishment of debt in the consolidated statements of operations. Amortization of deferred financing costs is recorded in interest expense and totaled $909,000,  $906,000 and $1,103,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Customer Deposits and Advances.  Certain customers are offered a prepayment program which requires a customer to pay a fixed periodic amount or to otherwise prepay a portion of their anticipated product purchases. Customer prepayments in excess of associated billings are classified as customer deposits and advances in the consolidated balance sheets.

Revenue Recognition.  We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller’s price to the buyer is fixed and determinable and collectability is reasonably assured.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the consolidated statements of operations.

Crude Oil Pipelines and Storage.  The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, we enter into sale and purchase contracts with counterparties instead of pipeline transportation agreements. In such cases, we assess the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. In addition, we also provide crude oil transportation services to third party customers.

Refined Products Terminals and Storage.  We generate fee-based revenues for terminal and storage services with longstanding customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Such fee-based revenues are recognized when services are proved upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

NGLs Distributions and Sales.  Revenues from the NGLs distributions and sales are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees.

Operating expenses.  Operating expenses primarily include personnel, vehicle, delivery, handling, office, selling, and other expenses related to the distribution, terminal and storage of products and related supplies.

Expenses associated with the delivery of products to customers (including vehicle expenses, expenses of delivery personnel and vehicle repair and maintenance) are classified as operating expenses in the consolidated statements of operations.

General and administrative expenses.  General and administrative expenses primarily include wages and benefits and department related costs for human resources, legal, finance and accounting, administrative support and supply.

Fair value measurement.  We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. We determine fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The fair value of our derivatives (see Note 12) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The fair value of our contingent liabilities (see Note 5) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). We do not have any other assets or liabilities measured at fair value on a recurring basis.

Our other financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and long term debt. The carrying value of our trade and other receivables, accounts payable and accrued expenses approximates fair value due to their highly liquid nature, short term maturity, or competitive rates assigned to these financial instruments. The fair value of long-term debt approximates the carrying value as the underlying instruments bear interest at rates similar to current rates offered to us for debt with the same remaining maturities.

Concentration Risk.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have not experienced any losses related to these balances.

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues from transactions with an external customer amounting to 10% or more of revenue are disclosed below, together with the identity of the reportable segment.

		Year Ended December 31,
Customer	ReportableSegment	2015	2014	2013
		(inthousands)
Customer A	Crudeoil pipelines and storage, NGLs distribution and sales	252,969	164,115	*
Customer B	Crudeoil pipelines and storage, Refined products terminals and storage	*	90,923	48,544

* Revenues are less than 10% of the total revenues during the period.

We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

Income Taxes.  We are a limited partnership, and therefore not directly subject to federal income taxes or most state income taxes. Our taxable income (loss) will be included in the federal income tax returns filed by the individual partners. Accordingly, no federal income tax provision has been made in our consolidated financial statements since the income tax is an obligation of the partners. We are subject to the Texas margin tax, which is reported in income tax expense in the consolidated statements of operations.

ASC 740, “Income Taxes”, requires the evaluation of tax positions taken or expected to be taken in the course of preparing our state tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe we have any tax positions taken within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions as part of our income tax expense, when and if they become applicable.

Equity-Based Compensation.  We account for equity based compensation by recognizing the fair value of awards on the grant date or the date of modification, as applicable, into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required.

Comprehensive Loss.  For the years ended December 31, 2015, 2014 and 2013, comprehensive loss was equal to net loss.

Recent Accounting Pronouncements.  In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 requires equity investments to be measured at fair value with changes in fair value recognized in net income; simplifies the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; requires separate presentation of financial assets and financial liabilities by measurement category and form of financial assets on the balance sheet or the accompanying notes to the financial statements and clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. This standard does not allow for early adoption except related to credit risk adjustment in other comprehensive income. The adoption of ASU 2016-01 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This ASU is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early application permitted and, upon adoption, may be applied either prospectively or retrospectively. We early adopted, retrospectively, ASU 2015-17. There is no impact from the adoption of this ASU as our deferred taxes are already presented under the non-current classification for all periods presented.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). ASU 2015-16 changes how the acquirer recognizes adjustments to the provisional amounts of a business combination that are identified during the measurement period  from a retrospective application of all affected financial periods to be recorded in the reporting period in which the adjustment amounts are determined. Additionally, the company needs to disclose, of the amounts recorded in current periods, what amounts would have been reported in previous periods if the adjustments had been recognized at the acquisition date.  ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015.  Early adoption of this ASU is permitted. The adoption of ASU 2015-16 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). ASU 2015-15 provides SEC Staff guidance to ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost, as it relates to debt issuance cost associated with line-of-credit arrangements. The SEC staff recognized that ASU 2015-03 did not address presentation or subsequent measurement of debt issuances cost related to line-of-credit arrangements and noted that the SEC Staff wouldn’t object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings of the line-of credit arrangement. ASU 2015-15 was adopted in the third quarter of 2015 with ASU 2015-03 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

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

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

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

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

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

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

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Discontinued Operations

12 Months Ended

Dec. 31, 2015

Discontinued Operations

Discontinued Operations

3. Discontinued Operations

Mid-Continent. On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”) to JP Development, simultaneous with JP Development’s sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9,685,000, in cash, which included certain adjustments related to inventory and other working capital items. We expect to recognize a loss on disposal of $12,909,000 related to the Mid-Continent Business. As of December 31, 2015, the Mid-Continent Business met all the criteria to be classified as asset held for sale in accordance with ASC 360, therefore, we classified all the related assets and liabilities as held for sale in the consolidated balance sheets. In addition, we allocated $7,939,000 of goodwill to the Mid-Continent Business, which was based on the relative fair value of the disposed Mid-Continent Business and the portion of the crude oil supply and logistics reporting unit that was retained by us. The $7,939,000 was subsequently impaired and contributed to the overall net loss from discontinued operations. The operating results of the Mid-Continent Business have been classified as discontinued operations for all periods presented in the consolidated statements of operations. We combined the cash flows from the Mid-Continent Business with the cash flows from continuing operations for all periods presented in the consolidated statements of cash flows. The Mid-Continent Business will not generate any continuing cash flows subsequent to the date of disposition. Prior to the classification as discontinued operations, we reported the Mid-Continent Business in our crude oil pipelines and storage segment. The following table summarizes selected financial information related to the Mid-Continent Business’ operations in the years ended December 31, 2015, 2014 and 2013.

Consolidated Statements of Operations

The discontinued operations of the Mid-Continent Business are summarized below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands, except unit and per unit data)
REVENUES
Crude oil sales	$	429,716	$	967,359	$	1,711,036
Gathering, transportation and storage fees		16		31		204
Other revenues		52		90		124
Total revenues		429,784		967,480		1,711,364
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		426,886		961,428		1,687,827
Operating expense		1,402		1,930		4,197
General and administrative		867		936		996
Impairment of goodwill and assets held for sale		12,909		—		—
Depreciation and amortization		2,281		2,258		2,358
Loss on disposal of assets, net		119		229		—
Total costs and expenses		444,464		966,781		1,695,378
OPERATING INCOME (LOSS)		(14,680)		699		15,986
OTHER INCOME (EXPENSE)
Interest expense		(296)		(412)		(830)
Loss on extinguishment of debt		—		—		—
Other income, net		25		46		1
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES		(14,951)		333		15,157
Income tax (expense) benefit		—		—		—
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	(14,951)	$	333	$	15,157

Consolidated Balance Sheets

The current and non-current assets and liabilities of the Mid-Continent Business are as follows:

	December 31,		December 31,
	2015		2014
	(in thousands)
ASSETS
Current assets
Inventory	$	2,692	$	15,149
Prepaid expenses and other current assets		38		—
Total Current assets of discontinued operations held for sale		2,730		15,149
Non-current assets
Property, plant and equipment, net		5,203		10,458
Goodwill		—		7,939
Intangible assets, net		1,138		2,981
Deferred financing costs and other assets, net		303		343
Total Non-current assets of discontinued operations held for sale		6,644		21,721
Total Assets of discontinued operations held for sale	$	9,374	$	36,870
LIABILITIES
Current liabilities
Accrued liabilities	$	640	$	—
Total Current liabilities of discontinued operations held for sale	$	640	$	—

The following table summarizes other selected financial information related to the Mid-Continent Business.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Depreciation	$	1,127	$	1,104	$	1,204
Amortization		1,154		1,154		1,154
Capital expenditures		637		316		1,327
Other operating noncash items related to discontinued operations:
Impairment on goodwill and assets held for sale	$	12,909	$	—	$	—
Derivative valuation changes		630		—		—
Loss on disposal of assets		119		229		—
Non-cash inventory LCM adjustments		—		222		—
Investing noncash items related to discontinued operations:
Accrued capital expenditures	$	—	$	218	$	—

Bakken Business. On June 30, 2014, we (“Seller”) entered into and simultaneously closed an Asset Purchase Agreement with Gold Spur Trucking, LLC (“Buyer”), pursuant to which the Seller sold all the trucking and related assets and activities in North Dakota, Montana and Wyoming (the “Bakken Business”) to the Buyer for a purchase price of $9,100,000. As a result, we recognized a loss on this sale of approximately $7,288,000 during the second quarter of 2014, which primarily relates to the write-off of a customer contract associated with the Bakken Business. In addition, immediately prior to the sale, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the crude oil supply and logistics reporting unit that was retained by us. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.

The Bakken Business operations have been classified as discontinued operations for all periods in the consolidated statements of operations. We combined the cash flows from the Bakken Business with the cash flows from continuing operations for all periods presented in the consolidated statements of cash flows. The Bakken Business will not generate any continuing cash flows subsequent to the date of disposition. Prior to the classification as discontinued operations, we reported the Bakken Business in our crude oil pipelines and storage segment. The following table summarizes selected financial information related to the Bakken Business’s operations in the years ended December 31,  2014 and 2013.

		Year Ended December 31,
		2014		2013
	(in thousands)
Revenues from discontinued operations	$	7,865	$	19,283
Net loss of discontinued operations, including loss on disposal of $7,288 in 2014		(9,608)		(1,182)

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Net Loss Per Unit

12 Months Ended

Dec. 31, 2015

Net Loss Per Unit

Net Loss Per Unit

4. Net Loss Per Unit

Net loss per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO by the weighted-average number of common units and subordinated units outstanding for the period. Loss per limited partner unit is calculated in accordance with the two-class method for determining loss per unit for master limited partnerships (“MLPs”) when incentive distribution rights (“IDRs”) and other participating securities are present. The two-class method requires that loss per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. For the years ended December 31, 2015 and 2014, dilutive loss per unit was equal to basic loss per unit because all instruments were antidilutive.

On January 26, 2016, the Board of Directors of our general partner declared a cash distribution for the fourth quarter of 2015 of $0.325 per common unit and subordinated unit.  The distribution was paid on February 12, 2016 to unitholders of record as of February 5, 2016.

	Year ended December 31, 2015
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	24,172	$	23,571	$	47,743
Distributions in excess of net income		(46,002)		(45,446)		(91,448)
Net loss from continuing operations attributable to the limited partners	$	(21,830)	$	(21,875)	$	(43,705)
Net loss from discontinued operations attributable to the limited partners		(7,521)		(7,430)		(14,951)
Net loss attributable to the limited partners	$	(29,351)	$	(29,305)	$	(58,656)
Weighted average units outstanding:
Basic		18,373,594		18,151,700		36,525,294
Net loss per unit:
Basic and diluted from continuing operations	$	(1.19)	$	(1.20)
Basic and diluted from discontinued operations	$	(0.41)	$	(0.41)
Basic and diluted total	$	(1.60)	$	(1.61)

	Year ended December 31, 2014
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	5,523	$	5,491	$	11,014
Distributions in excess of net income		(14,983)		(14,981)		(29,964)
Net loss from continuing operations attributable to the limited partners	$	(9,460)	$	(9,490)	$	(18,950)
Net income from discontinued operations attributable to the limited partners		167		167		334
Net loss attributable to the limited partners	$	(9,293)	$	(9,323)	$	(18,616)
Weighted average units outstanding:
Basic		18,212,632		18,209,948		36,422,580
Net income (loss) per unit:
Basic and diluted from continuing operations	$	(0.52)	$	(0.52)
Basic and diluted from discontinued operations	$	0.01	$	0.01
Basic and diluted total	$	(0.51)	$	(0.51)

The following data shows securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the year ended December 31, 2015:

Phantom units 406,218

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Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2015

Acquisitions And Dispositions

Acquisitions and Dispositions

5. Acquisitions and Dispositions

2015 Acquisitions

Acquisition of Southern Propane Inc. On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company. The acquisition expanded the asset base and market share of our NGL distribution and sales segment, specifically the acceleration of our entry into the Houston, Texas market, as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16,292,000 consisted of a $12,475,000 cash payment that was paid on the acquisition date, and which was funded through the use of borrowings from our revolving credit facility, a $108,000 cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3,442,000 and a contingent earn-out liability with a value of $267,000 that is subject to the achievement of certain gross profit targets at Southern.  The earn-out period covers the period from June 2015 through December 2016, and the maximum earn-out that could be earned is $1,250,000. The common units issued with this acquisition were issued in a private offering conducted in accordance with the exemption from the registration requirements of Section 4(a)(2) of the Securities Act of 1933, as amended, as such units were issued to the owners of a business acquired in a privately negotiated transaction not involving any public offering or solicitation.

The fair value of the contingent earn-out liability was estimated by applying an expected present value technique based on the probability-weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The contingent earn-out was established at the time of the acquisition and is revalued at each reporting period. Based on the actual post-acquisition performance results and revised projections, we decreased the fair value of the Southern contingent earn-out liability to $243,000 as of December 31, 2015, which is recorded in Other long-term liabilities in the consolidated balance sheets. For the year ended December 31, 2015, we recognized $24,000 in income related to the changes in the fair value of the contingent earn-out liability which is included in Other income, net, in our consolidated statements of operations. 

The following table represents our allocation of the total purchase price of this acquisition to the assets acquired (in thousands):

Accounts receivable	$	932
Inventory		24
Total current assets		956
Property, plant and equipment		2,962
Intangible assets:
Customer relationships		6,163
Noncompete agreements		292
Trade names		113
Total identifiable net assets acquired		10,486
Goodwill		5,806
Net assets acquired	$	16,292

Goodwill associated with the Southern acquisition principally results from synergies expected from integrated operations. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names are amortized over an estimated useful life of one year, customer relationships are amortized over a weighted average useful life of 12 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.

Revenues attributable to Southern included in the consolidated statements of operations totaled $3,849,000 for the period from May 8, 2015 to December 31, 2015. We do not account for the operations of Southern on a stand-alone basis, therefore, it is impracticable to report the amounts of net income of Southern included in the consolidated statements of operations related to the post-acquisition periods.

2013 Acquisitions

The following acquisitions by JP Development were acquired by us in the Common Control Acquisition.

Acquisition of Wildcat Permian Services LLC.  On October 7, 2013, JP Development acquired all of the issued and outstanding equity interests of Wildcat Permian for a total consideration of $212,804,000 in cash. Wildcat Permian owns and operates a long-term contracted oil pipeline system in Crockett and Reagan Counties, Texas. On February 12, 2014, we acquired Wildcat Permian from JP Development as part of the Dropdown Assets as described in Note 1.

The acquisition extended our reach into the core of the rapidly developing Midland Basin, which further diversified our portfolio of transportation and storage assets.

The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed on October 7, 2013 (in thousands):

Cash	$	2,570
Accounts receivable		16,068
Inventory		283
Short-term prepaid asset		134
Total current assets		19,055
Property, plant and equipment		33,962
Long-term prepaid asset		951
Intangible assets:
Customer relationships		67,700
Total assets acquired		121,668
Total liabilities assumed		(17,227)
Total identifiable net assets acquired		104,441
Goodwill		108,363
Net assets acquired	$	212,804

Goodwill associated with the Wildcat Permian acquisition principally results from expected future growth potential as well as the synergies expected from integrations with our other crude oil business. We allocated $11,242,000 of the goodwill associated with the Wildcat Permian acquisition to our crude oil supply and logistics reporting unit. The fair value of the acquired intangible asset was estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Customer relationships are amortized over a weighted average useful life of 17 years.

Revenues attributable to Wildcat Permian and included in the consolidated statements of operations totaled $70,580,000,  $64,136,000 and $10,878,000 for the years ended December 31, 2015, and 2014, and the period from October 7, 2013 to December 31, 2013, respectively. We do not account for the operations of Wildcat Permian on a stand-alone basis, therefore, it is impracticable to report the amounts of earnings of Wildcat Permian included in the consolidated results of operations related to the post acquisition periods.

Other 2013 Acquisitions.In addition to the acquisition described above, in 2013, JP Development also acquired the businesses in the table noted below for a total purchase price of $27,048,000. The total consideration consisted of $23,085,000 paid in cash, JP Development’s investment in our Class C Common Units representing limited partner interests valued at $1,628,000, a contingent earn-out with a fair value of $1,280,000 that was subject to the achievement of certain trucking revenue goals at Alexander Oil Field Service, Inc. (“AOFS”), and a contingent earn-out with a fair value of $1,055,000 that is subject to the achievement of certain trucking revenue goals at Highway Pipeline, Inc. (“HPI”). The AOFS earn-out period covers the period from September 1, 2013 to August 31, 2015, and the maximum earn-out which could be earned was $1,628,000 over the course of two years. The HPI earn-out period covers the period from January 1, 2014 to December 31, 2016, and the maximum earn-out that could be earned is $3,000,000 over the course of three years.

The fair value measure of the contingent earn-outs was estimated by applying an expected present value technique based on the probability- weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. The contingent earn-outs were established at the time of the acquisitions and are revalued at each reporting period. We estimated the fair value of the AOFS contingent earn-out liability to be $790,000 as of December 31, 2014. In the third quarter of 2015, we paid $488,000 as a settlement of the AOFS contingent earn-out. As of December 31, 2014, the fair value of the HPI contingent earn-out liability was $1,367,000. We decreased the fair value of the HPI contingent earn-out liability to $234,000 as of December 31, 2015, based on the actual post-acquisition performance results of the business as well as our revised expectation of the probable or possible future outcome.  As of December 31, 2015, the HPI liability is recorded in Other-long term liabilities in the consolidated balance sheets. For the years ended December 31, 2015 and 2014, we recognized income of $1,435,000 and losses of $435,000, respectively, related to the changes in fair value of the AOFS and HPI liabilities, which is included in Other income, net, in our consolidated statements of operations.

Dateof acquisition	Name of acquired entity	Totalpurchaseprice
		(inthousands)
July 15, 2013	BMHPropane, LLC (d/b/a Valley Gas)	$	2,437
August 30, 2013	Alexander Oil Field Service, Inc.		7,792
October 11, 2013	Highway Pipeline, Inc.		16,819

On February 12, 2014, we acquired the above businesses from JP Development in the Common Control Acquisition described in Note 1.

The following table represents the allocation of the aggregated purchase price to the assets acquired related to the three acquisitions described above, which are individually insignificant at their respective original acquisition dates by JP Development (in thousands):

Accounts receivable	$	504
Inventory		15
Total current assets		519
Property, plant and equipment		8,503
Intangible assets:
Trade names and trademarks		286
Customer relationships		8,022
Noncompete agreements		429
Total assets acquired		17,759
Total liabilities assumed		(475)
Total identifiable net assets acquired		17,284
Goodwill		9,764
Net assets acquired	$	27,048

The goodwill amounts noted for all 2013 acquisitions reflect the difference between purchase prices less the fair value of net assets acquired. Goodwill associated with these acquisitions principally results from synergies expected from integrated operations and from assembled workforce. We do not believe that the acquired intangible assets have an significant residual value at the end of their respective useful lives. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names and trademarks are amortized over an estimated useful life of 2 years, customer relationships are amortized over a weighted average useful life of 6 years, and non-compete agreements are amortized over an estimated useful life of 3 years.

Revenues attributable to the three acquisitions above and included in the consolidated statements of operations totaled $14,008,000,  $18,329,000 and $5,781,000, for the years ended December 31, 2015, 2014 and the period from each respective acquisition date to December 31, 2013, respectively. We do not account for the operations of  these acquisitions on a stand-alone basis, therefore, it is impracticable to report the amounts of earnings of these acquisitons included in the consolidated results of operations related to the post acquisition periods.

Pro Forma Information

The following unaudited pro forma information summarizes the results of operations for the year ended December 31, 2013 as if the significant acquisition of JP Permian (effectively acquired by us on October 7, 2013—see Note 1) had been completed at the beginning of the year. Financial information of certain acquisitions was impractical to obtain and accordingly have not been included in the proforma financial information presented below.

The pro forma data combines our consolidated results with those of JP Permian (prior to acquisition) for the period shown. The results are adjusted for amortization, depreciation, interest expense and income taxes relating to the acquisition. No effect has been given to cost reductions or operating synergies in this presentation. These pro forma amounts do not purport to be indicative of the results that would have actually been achieved if the acquisitions had occurred as of the beginning of the period presented or that may be achieved in the future. The pro forma amounts are as follows:

	Year ended December 31, 2013
	(inthousands)
	(unaudited)
Pro forma consolidated revenue from continuing operations	$	393,837
Pro forma consolidated net loss from continuing operations	$	(32,501)

Disposition of crude oil supply and logistics assets. On September 30, 2015, we entered into an asset purchase agreement pursuant to which we sold certain crude oil supply and logistics assets for a sales price of $1,914,000. We closed the transaction on November 2, 2015 and recognized a gain on disposal of $1,046,000.

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Inventory

12 Months Ended

Dec. 31, 2015

Inventory

Inventory

6. Inventory

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

	December 31,
	2015		2014
	(in thousands)
Crude Oil	$	338	$	162
NGLs		2,364		3,342
Refined Products		430		445
Materials, supplies and equipment		1,654		1,728
Total inventory	$	4,786	$	5,677

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Property, Plant and Equipment, net

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment, net

Property, Plant and Equipment, net

7. Property, Plant and Equipment, net

Property, plant and equipment, net consists of the following as of December 31, 2015 and 2014:

	December 31,
	2015		2014
	(in thousands)
Land	$	6,874	$	6,874
Buildings and improvements		12,561		12,045
Transportation equipment		46,582		39,388
Storage and propane tanks		151,988		139,721
Pipelines and linefill		77,295		54,059
Office furniture and fixtures		9,701		8,245
Other equipment		48,171		25,892
Construction-in-progress		12,763		15,175
Total property, plant and equipment		365,935		301,399
Less: accumulated depreciation		(74,481)		(49,709)
Property, plant and equipment, net	$	291,454	$	251,690

Depreciation expense totaled $29,391,000,  $23,514,000 and $18,779,000 for the years ended December 31, 2015, 2014 and 2013, respectively, which is included in depreciation and amortization expense in the consolidated statements of operations. Depreciation expense amounts have been adjusted by $1,127,000,  $1,685,000 and $2,348,000 for the years ended December 31, 2015, 2014 and 2013, respectively, to present the Mid-Continent and Bakken Business’s operations as discontinued operations.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets

Goodwill and Intangible Assets

8. Goodwill and Intangible Assets

Intangible assets consist of the following for the years ended December 31, 2015 and 2014:

	December 31, 2015
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
		(in thousands)
Customer relationships	$	82,630	$	(20,761)	$	61,869
Noncompete agreements		3,575		(2,664)		911
Trade names		553		(139)		414
Customer contract		95,594		(24,538)		71,056
Other		198		(16)		182
Total	$	182,550	$	(48,118)	$	134,432
	December 31, 2014
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
	(in thousands)
Customer relationships	$	76,466	$	(14,275)	$	62,191
Noncompete agreements		3,728		(2,283)		1,445
Trade names		2,147		(583)		1,564
Customer contract		95,594		(15,662)		79,932
Other		209		(11)		198
Total	$	178,144	$	(32,814)	$	145,330

In connection with the sale of the Mid-Continent Business, which was classified as held for sale at December 31, 2015, we recorded an impairment charge of $689,000 related to customer relationships during the year ended December 31, 2015, which is classified in net loss from discontinued operations in the consolidated statements of operations.  In addition, as a result of the sale of the Bakken Business, we wrote-off $8,060,000 in customer contracts during the year ended December 31, 2014 (see Note 3).

Amortization expense totaled $17,461,000,$16,716,000 and $12,208,000 for December 31, 2015, 2014 and 2013, respectively, which is included in depreciation and amortization expense in the consolidatedstatements of operations.  Amortization expense amounts have been adjusted by $1,154,000,  $2,007,000 and $2,860,000 for the years ended December 31, 2015, 2014 and 2013, respectively, to present the Mid-Continent and Bakken Business’s operations as discontinued operations.

We amortize intangible assets over their estimated benefit period on a straight-line basis.

The estimated future amortization expense for amortizable intangible assets to be recognized is as follows (in thousands):

2016	$	16,163
2017		15,754
2018		15,484
2019		13,499
2020		10,790
Thereafter		62,742
Total	$	134,432

Goodwill activity in 2014 and 2015 consists of the following:

			Refined
	Crude oil		products		NGL
	pipelines and		terminals and		distribution
	storage		storage		and sales		Total
	(in thousands)
Balance at January 1, 2014	$	150,268	$	61,163	$	31,335	$	242,766
Disposals		(1,984)		—		—		(1,984)
Balance at December 31, 2014		148,284		61,163		31,335		240,782
Goodwill acquired during the year		—		—		5,806		5,806
Goodwill impairment		(23,574)		—		(6,322)		(29,896)
Balance at December 31, 2015	$	124,710	$	61,163	$	30,819	$	216,692

We recorded a goodwill impairment charge of $29,896,000 during the year ended December 31, 2015 related to our Crude Oil Supply and Logistics and JP Liquids reporting units. Additionally, in connection with the sale of the Mid-Continent Business, we recorded a goodwill impairment charge of $7,939,000 during the year ended December 31, 2015 which is classified in net loss from discontinuing operations in the consolidated statements of operations.

During the year ended December 31, 2014, we recorded a decrease in goodwill of $1,984,000 related to the sale of the Bakken Business.

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Accrued Liabilities

12 Months Ended

Dec. 31, 2015

Accrued Liabilities

Accrued Liabilities

9.Accrued Liabilities

Accrued liabilities are comprised of the following as of December 31, 2015 and 2014:

	December 31,
	2015		2014
	(inthousands)
Taxes payable	$	1,204	$	1,915
Accrued payroll and employee benefits		4,756		8,148
Accrued professional fees		696		462
Royalties payable		4,163		4,281
Short-term derivative liabilities		358		10,157
Other		4,083		4,008
Total accrued liabilities	$	15,260	$	28,971

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Capital Leases and Other Short-Term Debt

12 Months Ended

Dec. 31, 2015

Capital Leases and Other Short-Term Debt

Capital Leases and Other Short Term Debt

10. Capital Leases and Other Short-Term Debt

Capital Leases. We have certain leases for buildings, transportation equipment and office equipment, which are accounted for as capital leases. The leases mature between 2016 and 2021. Assets under capital lease are recorded within property, plant and equipment, net in the consolidated balance sheets. The following is a summary of assets held under such agreements.

	December 31,
	2015		2014
	(inthousands)
Buildings and improvements	$	16	$	138
Transportation equipment		167		261
Office furniture and equipment		133		129
Other equipment		35		49
		351		577
Less: Accumulated depreciation		(197)		(254)
Assets under capital lease, net	$	154	$	323

Scheduled repayments of capital lease obligations are as follows (in thousands):

Years ending December 31,
2016	$	153
2017		116
2018		40
2019		31
2020		22
Thereafter		11
		373
Less: amounts representing interest		(137)
Total obligations under capital leases		236
Less: current portion		(107)
Long-term capital lease obligation	$	129

The long term capital lease obligation is included within other long-term liabilities in the consolidated balance sheets.

Other Short-Term Debt. In addition, we had $91,000 bank overdrafts outstanding as of December 31, 2014.

We financed a portion of our annual insurance premium in 2013. During the year ended December 31, 2014, we repaid the outstanding balance under this arrangement of $49,000. We no longer finance our insurance premiums.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Long-Term Debt

Long-Term Debt

11. Long-Term Debt

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

	December 31,
	2015		2014
	(in thousands)
Bank of America revolving loan	$	162,000	$	83,000
HBH note payable		1,077		1,277
Non-compete notes payable		117		231
Total long-term debt	$	163,194	$	84,508
Less: Current maturities		(454)		(383)
Total long-term debt, net of current maturities	$	162,740	$	84,125

Bank of America Credit Agreement. On February 12, 2014, we entered into a credit agreement with Bank of America, N.A. (the “BOA Credit Agreement”), which is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions, not in contravention of law of the loan documents and to pay off our existing WFB commitments and F&M Loans (as described below). The BOA Credit Agreement consists of a $275,000,000 revolving loan, which includes a sub-limit of up to $100,000,000 for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275,000,000 up to $425,000,000, subject to obtaining additional or increased lender commitments. The BOA Credit Agreement will mature on February 12, 2019. Our obligations under the BOA Credit Agreement are collateralized by substantially all of our assets.

Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable rate. The applicable rate is (a) 1.25% for prime rate borrowings and 2.25% for LIBOR borrowings. The commitment fee is subject to an adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement and (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.

As of December 31, 2015, the unused balance of the BOA Credit Agreement was $86,870,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $26,130,000 at December 31, 2015. We are required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on (i) prior to the IPO, the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement and (ii) on or after the IPO, the Consolidated Net Total Leverage Ratio, as defined in the BOA Credit Agreement.

The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:

Prior to the IPO

Maintenance of certain financial covenants including a consolidated total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes (which will be increased to 4.75 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated total leverage ratio of not more than 4.75 to 1.00 from and after the issuance of certain unsecured notes, a consolidated senior secured leverage ratio of not more than 3.00 to 1.00 from and after the issuance of certain unsecured notes, a consolidated working capital (as defined in the BOA Credit Agreement) of not less than $15,000,000 and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.

Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.

After the IPO

Maintenance of certain financial covenants including a consolidated net total leverage ratio of not more than 4.50 to 1.00 prior to the issuance of certain unsecured notes, a consolidated net total leverage ratio of not more than 5.00 to 1.00 from and after the issuance of certain unsecured notes, a consolidated senior secured net leverage ratio of not more than 3:50 to 1:00 from and after the issuance of certain unsecured notes, available liquidity (as defined in the BOA Credit Agreement) of not less than $25,000,000 and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.

Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.

Beginning in March 2015, we were inadvertently not in full compliance with previously existing restrictions under our revolving credit facility due to our engaging in certain financial swap contracts with a lender in our revolving credit facility. Such noncompliance was waived pursuant to Amendment No. 4. The financial swap contracts were executed as a part of our normal course hedging practices in compliance with our risk management policy and are now permitted under the terms of Amendment No. 4.Prior to February 23, 2016, our revolving credit facility contained a covenant requiring our consolidated working capital, as defined in the credit agreement, to be not less than $15,000,000. We were not in compliance with the consolidated working capital covenant as of December 31, 2015, which noncompliance was waived and which covenant was removed and the available liquidity covenant was added pursuant to Amendment No. 5.

HBH Note Payable.  We issued a $2,012,500 non-interest bearing promissory note in conjunction with the acquisition of HBH on November 15, 2011. The carrying value of this note is $1,077,000 and $1,277,000 as of December 31, 2015 and December 31, 2014, respectively, which is based on an interest rate of 5.0%. This balance is payable every January and July through December 31, 2016 based on the number of meter connections above a threshold. The minimum amount due is $2,012,500. The final remaining balance on this loan is due in full on December 31, 2016. Accretion expense, included as a component of interest expense, totaled $55,000,  $66,000 and $69,000 for the 2015, 2014 and 2013, respectively. The fair value measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs.

Non-Compete Notes Payable.  As part of the acquisition of Heritage Propane Express, LLC (“HPX”) in June 2012, we acquired several promissory notes, which were issued prior to acquisition by HPX as consideration for several non-compete agreements unrelated to the acquisition transaction. Each of the agreements has a five year term and is non-interest bearing. The fair value of the agreements is $117,000 and $231,000 at December 31, 2015 and December 31, 2014, respectively, which is based on an effective imputed interest rate of 3.5%.

Wells Fargo Credit Agreement. We had a $20,000,000 working capital revolving credit facility and a $180,000,000 acquisition revolving credit facility with Wells Fargo Bank, N.A. (the “WFB Credit Agreement”). Our outstanding borrowings under the WFB Credit Agreement were collateralized by substantially all of our assets.

On February 12, 2014, we entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement. As a result of the termination of the WFB Credit Agreement, we wrote off $1,634,000 of deferred financing costs during the year ended December 31, 2014.

F&M Bank & Trust Company Credit Agreement. On July 20, 2012, we entered into an amended and restated credit agreement with F&M Bank & Trust Company for the purchase of new, and the refinancing of existing, vehicles and equipment. The F&M Bank Credit Agreement consisted of several term loans (collectively, “F&M Loans”). Our obligations under the F&M Loans were collateralized by our vehicles and equipment financed by these loans.

On February 12, 2014, the outstanding balance on the F&M Loans of $4,135,000 was paid in full with the proceeds from the BOA Credit Agreement.

Reynolds Note Payable.  We issued a $645,000 non-interest bearing promissory note as partial consideration for the acquisition of Reynolds Brother Propane on May 1, 2012. The note was payable in two installments of $295,000 and $350,000 at the first and second anniversary of the acquisition closing date (i.e. May 1, 2013 and May 1, 2014), respectively. On May 1, 2014, we repaid the promissory note in full.

Related Party Note Payable. On November 5, 2013, we issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. On March 20, 2014, we repaid the promissory note in full.

Scheduled principal repayments of long-term debt for each of the next five years ending December 31 and thereafter are as follows (in thousands):

2016	$	454
2017		740
2018		—
2019		162,000
2020		—
Thereafter		—
Total	$	163,194

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Derivative Instruments

12 Months Ended

Dec. 31, 2015

Derivative Instruments

Derivative Instruments

12. Derivative Instruments

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

Commodity Price Risk. Our normal business activities expose us to risks associated with changes in the market price of crude oil and propane, among other commodities. Management believes it is prudent to limit our exposure to these risks, which include our (i) propane purchases, (ii) pre-existing or anticipated physical crude oil sales and (iii) certain crude oil held in inventory.  To meet this objective, we use a combination of fixed price swap and forward contracts. At times, we may also terminate or unwind hedges or portions of hedges in order to meet cash flow objectives or when the expected future volumes do not support the level of hedges. Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered.  While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. 

In the first quarter of 2015, we entered into several long-term fixed price forward sale contracts related to certain barrels of crude oil we had on hand as of December 31, 2014, effectively locking these barrels at higher future sales prices in future periods.  These forward sale contracts are intended to mitigate the effect of the decline in crude oil prices, but do not qualify for NPNS accounting under GAAP, because we normally buy and sell crude oil inventory either within the same month or in the following month. As a result, these longer than normal term forward sale contracts were given mark-to-market accounting treatment. As these forward sale contracts relate to the marketing assets in our Mid-Continent Business (see Note 3), the fair values of the forward contracts have been classified as held for sale in the consolidated balance sheets.  As of December 31, 2015, the fair value of the Mid-Continent forward contracts is $630,000 and is included in current liabilities of discontinued operations held for sale in the consolidated balance sheets.

  In August 2015, we paid approximately $8,745,000 to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the NPNS exception as of December 31, 2015 and 2014, none of which were designated as hedges for accounting purposes.

	December 31, 2015		December 31, 2014
	NotionalVolume	Maturity	Notional Volume	Maturity
Fixed Price Swaps :
Propane (Gallons)	8,614,631	Jan 2016 - July 2017	27,958,302	Jan 2015 - Dec 2016
Crude Oil (Barrels)	(93,000)	Jan 2016	—	—

Interest Rate Risk. We are exposed to variable interest rate risk as a result of variable-rate borrowings under our revolving credit facilities. We entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of our debt with a variable-rate component. These swaps changed the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, we received variable interest rate payments and made fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that was swapped.  As of December 31, 2014, our outstanding interest rate swap contracts contained a notional amount of $75,000,000.  Our interest rate swap agreements expired in July and September 2015.

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

Fair Value of Derivative Instruments. We measure derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize indirectly observable (“level 2”) inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of our derivative contracts are designated as hedging instruments. The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets as of December 31, 2015 and 2014.

		Asset Derivatives				Liability Derivatives
		December 31,		December 31,		December 31,		December 31,
	Balance Sheet Location	2015		2014		2015		2014
		(in thousands)
Commodity swaps	Prepaid expenses and other current assets	$	92	$	—	$	—	$	—
Commodity swaps	Accrued liabilities		—		—		(450)		(8,941)
Commodity swaps	Other long-term liabilities		—		—		(24)		(3,251)
Interest rate swaps	Accrued Liabilities		—		—		—		(158)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the consolidated balance sheet as of December 31, 2015 that are subject to enforceable master netting arrangements.

	As of December 31, 2015
	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented in the Balance Sheet		Financial Collateral		Net Amount
	(in thousands)
Derivative Assets:
Derivative contracts - current	$	92	$	(92)	$	—	$	—	$	—
Derivative contracts - noncurrent		—		—		—		—		—
Derivative Liabilities:
Derivative contracts - current	$	450	$	(92)	$	358	$	—	$	358
Derivative contracts - noncurrent		24		—		24		—		24

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

The following tables summarize the amounts recognized with respect to our derivative instruments within the consolidated statements of operations.

	Location of Gain (Loss) Recognized in	Amount of Gain/(Loss) Recognized in Income on Derivatives
	Income on Derivatives	December 31, 2015		December 31, 2014		December 31, 2013
		(in thousands)
Commodity derivatives (swaps)	Cost of sales		(3,056)		(13,762)		902
Interest rate swaps	Interest expense		(27)		(227)		(168)

For the year ended December 31, 2015, we recognized $1,962,000 in total losses with respect to derivative instruments related to the Mid-Continent business which have been included in amounts classified as discontinued operations in the consolidated statements of operations.

In the consolidated statements of cash flows, the effects of settlements of derivative instruments are classified as operating activities, consistent with the related transactions.

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Partners' Capital

12 Months Ended

Dec. 31, 2015

Partners' Capital

Partners' Capital

13. Partners’ Capital

Initial Public Offering.  On October 7, 2014, we closed on our IPO of 13,750,000 common units, representing a 37.7% interest in us. Total proceeds from the sale of the units were $257.1 million, net of underwriting discounts and structuring fees. See Note 1 for details of the IPO and recapitalization transactions.

Preferred Units. On August 1, 2013, we converted all 524,746 of the then-outstanding Series A Convertible Preferred Units, all 552,348 of the then-outstanding Series B Convertible Preferred Units, and all 59,270 of the then-outstanding Series C Convertible Preferred Units previously issued to Lonestar, on a one-for-one basis into Class A Common Units.

On March 28, 2014, we authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the “Series D Preferred Units”) for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the “Subscription Agreement”) by and among us, JP Energy GP II LLC, a Delaware limited liability company and general partner to the Partnership (the “General Partner”) and Lonestar. This transaction resulted in proceeds to us of  $40,000,000. During the year ended December 31, 2014, we issued to Lonestar 110,727 Series D PIK Units related to the distributions earned for the three months ended June 30, 2014 and the three months ended September 30, 2014. On October 7, 2014, we paid $42,436,000 from proceeds related to the IPO to redeem all then outstanding Series D Preferred Units.

Common Units. Throughout 2013, we issued an aggregate of 88,114 Class C Common Units to JP Development for total net proceeds of $3,128,000.

On February 12, 2014, we issued 363,636 Class A Common Units to Lonestar for total net proceeds of $8,000,000.

With the exception of the distribution of proceeds upon a “Change of Control Event” as described in the Partnership Agreement, all Class A Common Units, Class B Common Units, and Class C Common Units (collectively, the “Existing Common Units”) had the same terms and conditions.

Prior to the closing of the IPO, the Existing Common Units were split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units. An aggregate of 18,213,502 of the Existing Common Units held by existing partners were automatically converted into 18,213,502 subordinated units. Subsequent to the closing of our IPO, the remaining 4,463,502 Existing Common Units were automatically converted into common units on a one-to-on basis and we issued 13,750,000 common units to the public.

On May 8, 2015, in connection with the Southern acquisition, we issued 266,951 common units valued at $3,442,000.

Subordinated Units. Our Amended Partnership Agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash, defined below, each quarter in an amount equal to $0.3250 per common unit, which amount is defined in our Amended Partnership Agreement as the minimum quarterly distribution (“MQD”), plus any arrearages in the payment of the MQD on the common units from prior quarters, before any distributions of available cash may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the MQD plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution milestones described in the Amended Partnership Agreement have been met.

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

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

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

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

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

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

General Partner Interest and IDRs. As of December 31, 2013,the General Partner had 45 general partner units. On October 7, 2014, subsequent to the closing of the IPO, the 45 general partner units were recharacterized as a non-economic general partners interest in us.

The non-economic general partner interest in us does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us, and will be entitled to receive distributions on such interests.

Incentive distribution rights represent the right to receive an increasing percentage (15.0%,  25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our Amended Partnership Agreement.

The following discussion assumes that there are no arrearages on the common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

first,  100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.37375 per unit for that quarter (the "first target distribution");

second,  85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.40625 per unit for that quarter (the "second target distribution");

third,  75.0% to all unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.4875 per unit for that quarter (the “third target distribution”); and

thereafter,  50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).

Distributions. Prior to our IPO, our Partnership Agreement required that, within 60 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 the General Partner. In connection with the IPO, we entered into the Amended Partnership Agreement, which requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date, subject to certain terms and conditions. During the year ended December 31, 2014, we did not make any cash distributions.  During the years ended December 31, 2015 and 2013, we made the following cash distributions per unit:

	Cash Distribution
Distribution Date	(per unit)
February 2013	$	0.5000
July 2013		0.5000
August 2013		0.5000
February 2015		0.3038	(1)
May 2015		0.3250
August 2015		0.3250
November 2015		0.3250

(1) Represents a prorated amount of our minimum quarterly distribution of$0.325per common unit, based on the number of days between the closing of the IPO on October 7, 2014 and December 31, 2014.

We paid a cash distribution of $0.325 per common unit and subordinate unit on February 12, 2016.

Valuation of Units.  Prior to our IPO, fair value of the Class B and Class C common units was estimated based on enterprise value calculated using the discounted cash flow method (Level 3). Material unobservable inputs used to estimate the fair value include weighted average cost of capital (“WACC”) and market multiple used in calculating the terminal value.  The following table presents the inputs used on each major valuation date during 2013:

	December 31, 2013					April 19, 2013
WACC	10.71	%	-	11.21	%	9.41	%	-	9.91	%
Market multiple	12.05		-	12.55	times	10.5		-	11	times

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Unit-Based Compensation

12 Months Ended

Dec. 31, 2015

Unit-Based Compensation

Unit-Based Compensation

14. Unit-Based Compensation

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

The following table presents phantom units activity for the year ended December 31, 2015:

Phantom Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—	$	—
Service condition grants	497,479		12.84
Vested service condition	(8,250)		12.90
Forfeited service condition	(96,809)		12.26
Outstanding at the end of period	392,420		12.99

Total unit-based compensation expense related to our phantom units was $849,000 for the year ended December 31, 2015 which was recorded in general and administrative expense in the consolidated statement of operations.

We expect to recognize $2.5 million of compensation expense related to non-vested phantom units over a weighted average period of 1.6 years. We have estimated a weighted average forfeiture rate of 41% in calculating the unit-based compensation expense.

Restricted (Non-Vested) Common and Subordinated Units.  Prior to the completion of our IPO on October 7, 2014, from time to time, we granted service condition restricted class B common units to certain key employees. Such service condition restricted common units require the recipients’ continuous employment with us and vest, according to the vesting schedule in each respective grant agreement, over certain periods, typically three to five years.

Pursuant to certain employment agreements, as amended, between us and certain employees, we were obligated to grant restricted Class B common units to those employees upon their achievement of certain agreed-upon performance goals that were measured by different milestones. Different milestone achievements caused different amounts of restricted Class B common units to be awarded. The maximum amount of the restricted Class B common units that could have been issued pursuant to these employment agreements, as amended, was 100,000 units. Prior to year ended December 31, 2013, 75,000 restricted Class B common units were issued as a result of the employees’ achievement of certain milestones and the unit-based compensation expense related to these units have been fully recorded as general and administrative expenses in respective historical periods.  With respect to the remaining 25,000 restricted Class B common units to be issued, we estimated the probable number of years for the performance goals to be achieved and have recognized the related unit-based compensation expense over the estimated number of years.  During the second quarter of 2015, each employee terminated their employment with us prior to one employee achieving their performance goal related to the remaining 25,000 restricted Class B common units.  As a result, we reversed previously recognized unit-based compensation expense of $297,000.  

Fair value of the restricted class B common units equaled the fair value of our common unit at the respective grant dates. We estimate the fair value of our common unit by dividing the estimated total equity value by the number of outstanding units. Estimated total equity value was determined using the income approach of discounting the estimated future cash flow to its present value.

Immediately prior to the IPO, each of our Class B common unit was split into approximately 0.89 common unit, then approximately 80.3% of the common unit was converted into subordinate unit and the remaining 19.7% was converted into common unit.

During the years ended December 31, 2015, 2014 and 2013, unit-based compensation expense of $460,000,  $1,789,000 and $948,000, respectively, was recorded in general and administrative expense in the consolidated statements of operations related to these restricted units.

The following table presents restricted (non-vested) common, subordinated and class B common units during the years ended December 31, 2015, 2014 and 2013:

2015
	Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	31,012	$	24.36	126,553	$	24.36
Vested - service condition	(10,512)		25.37	(42,898)		25.37
Forfeited - service condition	(14,076)		22.89	(57,439)		22.89
Outstanding at the end of period	6,424		25.91	26,216		25.91

2014
	Class B Common Units			Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	177,867	$	25.58	—	$	—	—	$	—
Granted - service condition	90,000		19.64	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	(63,698)		24.21	—		—	—		—
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	(6,667)		34.91	—		—	—		—
Forfeited - performance condition	—		—	—		—	—		—
Conversion upon IPO	(197,502)		23.00	34,603		25.84	141,211		25.84
Granted - service condition	—		—	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	—		—	(876)		36.75	(3,576)		36.75
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	—		—	(2,715)		39.22	(11,082)		39.22
Forfeited - performance condition	—		—	—		—	—		—
Outstanding at the end of period	—		—	31,012		24.36	126,553		24.36

8
2013
Restricted (Non-Vested) Common Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	143,000	$	20.32
Granted - service condition	68,500		34.91
Granted - performance condition	—		—
Vested - service condition	(23,633)		23.37
Vested - performance condition	—		—
Forfeited - service condition	(10,000)		19.51
Forfeited - performance condition	—		—
Outstanding at the end of period	177,867		25.58

We make distributions to non-vested restricted units on a 1:1 ratio with the per unit distributions paid to common units. Upon the vesting of the restricted units, we intend to settle these obligations with common units. Accordingly, we expect to recognize an aggregate of $561,000 of compensation expense related to non-vested restricted units over a weighted average period of 1.42 years.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Commitments and Contingencies

15. Commitments and Contingencies

Legal Matters. We are involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on our consolidated financial statements.

Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.

Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting our activities. We have established procedures for the ongoing evaluation of our operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

We account for environmental contingencies in accordance with the ASC 410 related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed.

Liabilities are recorded when environmental assessments and/or clean- ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, we had no significant environmental matters.

Refined Products Terminals. In the third quarter of 2014, we discovered that certain elements of the product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal could under-deliver refined products to our customers and, consequently, recognize excess gains on refined products generated through the terminal’s normal terminal and storage process. We recognize revenues for refined product gains as the products are sold at the terminal based on current market prices. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards and regulations, and have discussed this matter with our customers and have returned a certain amount of refined products to the majority of our customers. Because there are numerous elements inherent in the product measurement process that could affect the amount of refined product gains generated at the terminal, it is not practicable for us to accurately quantify this amount or the discrete period of refined product gains previously recognized that were caused by these specific issues. However, using available operational data and certain management assumptions, we have reasonably estimated the volume of refined products to be returned to our customers of approximately 24,000 barrels. During 2014, we returned approximately 20,900 barrels to our customers, which amounts to a value of $2,092,000. As of December 31, 2014, we had approximately 3,100 barrels remaining that were due to our customers, at an estimated value of $167,000. Accordingly, we recorded a $2,259,000 charge to operating expense in the consolidated statement of operations for the year ended December 31, 2014. We completed the final settlement of the under-delivered product volumes in the third quarter of 2015, which resulted in a charge to operating expenses of $172,000 in the year ended December 31, 2015.

Asset retirement obligations (ARO).  We have contractual obligations to perform dismantlement and removal activities in the event that some assets, such as storage tanks, are abandoned. These obligations include varying levels of activity including completely removing the assets and returning the land to its original state. We have determined that the settlement dates related to the retirement obligations are indeterminate. The assets with indeterminate settlement dates have either been in existence for many years or are relatively new assets and with regular maintenance will continue to be in service for many years to come. In addition, it is not possible to predict when demand for the service will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated ARO’s and therefore, no ARO liability is recorded as of December 31, 2015 and 2014. Additionally, many of these assets could be re-deployed for a similar use. We will continue to monitor these assets and if sufficient information becomes available for us to reasonably determine the settlement dates, an ARO will be recorded for these assets in the relevant periods.

Operating Leases.  We leases various buildings, land, storage facilities, transportation vehicles and office equipment under operating leases. Certain of the leases contain renewal and purchase options. Our aggregate rental expense for such leases was $5,741,000,  $4,806,000 and $3,299,000 for the years ended December 31, 2015, 2014 and 2013, respectively. Additionally, we assumed a land lease in the acquisition of Parnon Storage, LLC on August 3, 2012. Equal payments of $10,000 are due each month over the remaining 42 year lease period with no implied interest rate noted in the lease agreement.

Minimum future payments under non-cancelable operating leases as of December 31, 2015 and thereafter are as follows (in thousands):

2016	$	5,116
2017		4,331
2018		3,776
2019		2,383
2020		718
Thereafter		4,877
	$	21,201

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Reportable Segments

12 Months Ended

Dec. 31, 2015

Reportable Segments

Reportable Segments

16. Reportable Segments

In the fourth quarter of 2015, we reorganized our business segments to match the change in our internal organization and management structure.  The segment changes reflect the focus of our chief operating decision maker (“CODM”) and how performance of operations is evaluated and resources are allocated.  Therefore, the results of our formerly reported crude oil supply and logistics segment have been combined into our crude oil pipelines and storage segment.  As a result of the reorganization, our operations currently consist of three business segments: (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales.  Accordingly, we have restated the items of segment information for the years ended December 31, 2014 and 2013 to reflect this new segment adjustment.

Our operations are located in the United States and are organized into three reportable segments: crude oil pipelines and storage; refined products terminals and storage; and NGL distribution and sales.

Crude oil pipelines and storage.  The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and consists of approximately 148 miles of high-pressure steel pipeline with throughput capacity of approximately 130,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 140,000 barrels of storage capacity.  We also operate a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.

The crude oil pipelines and storage segment also consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. We conduct crude oil supply activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. We also own a fleet of crude oil gathering and transportation trucks operating in and around highly prolific drilling areas such as the Eagle Ford shale and the Permian Basin. As described in Note 3, the disposition of the Mid-Continent Business and Bakken Business impacts the crude oil pipelines and storage segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information tables. Accordingly, we have recast the segment information.

Refined products terminals and storage.  The refined products terminals and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal has storage capacity of 550,000 barrels from 11 tanks and has eight loading lanes with automated truck loading equipment. The Caddo Mills terminal consists of 10 storage tanks with an aggregate capacity of approximately 770,000 barrels and has five loading lanes with automated truck loading equipment.  The North Little Rock terminal and the Caddo Mills terminal are primarily served by the Enterprise TE Products Pipeline Company LLC and the Explorer Pipeline, respectively.

NGL distribution and sales.  The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 48 states through a network of approximately 21,000 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the U.S., we sell NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. We also own a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.

Corporate and other. Corporate and other includes general partnership expenses associated with managing all of our reportable segments.

Our CODM evaluates the segments’ operating performance based on Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring.

The following tables reflect certain financial data for each reportable segment for the years ended December 31, 2015, 2014 and 2013.

	Year ended December 31,
	2015		2014		2013
	(in thousands)
External Revenues:
Crude oil pipelines and storage	$	480,527	$	495,971	$	186,993
Refined products terminals and storage		23,227		23,287		24,011
NGL distribution and sales		176,831		206,896		179,865
Total revenues	$	680,585	$	726,154	$	390,869
Cost of Sales, excluding depreciation and amortization:
Crude oil pipelines and storage	$	445,027	$	459,183	$	167,744
Refined products terminals and storage		8,649		6,453		4,683
NGL distribution and sales		76,618		126,686		105,488
Amounts not included in segment Adjusted EBITDA		(2,818)		13,360		(1,111)
Total cost of sales, excluding depreciation and amortization	$	527,476	$	605,682	$	276,804
Operating Expenses:
Crude oil pipelines and storage	$	9,238	$	7,928	$	7,405
Refined products terminals and storage		2,980		4,602		2,464
NGL distribution and sales		57,200		52,109		47,307
Amounts not included in segment Adjusted EBITDA		(41)		945		552
Total operating expenses	$	69,377	$	65,584	$	57,728
Depreciation and Amortization:
Crude oil pipelines and storage	$	20,356	$	17,240	$	10,335
Refined products terminals and storage		6,830		5,911		6,162
NGLs distribution and sales		18,628		16,163		13,981
Corporate and other		1,038		916		509
Total depreciation and amortization	$	46,852	$	40,230	$	30,987
Adjusted EBITDA:
Crude oil pipelines and storage	$	23,119	$	25,339	$	9,479
Refined products terminals and storage		10,867		10,723		16,100
NGL distribution and sales		30,896		15,511		15,518
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Capital Expenditures:
Crude oil pipelines and storage	$	42,919	$	36,691	$	4,410
Refined products terminals and storage		8,002		2,489		4,482
NGLs distribution and sales		18,587		16,557		16,009
Corporate and other		1,503		1,141		1,927
Total capital expenditures	$	71,011	$	56,878	$	26,828

A reconciliation of Adjusted EBITDA to net loss from continuing operations is included in the table below.

	Year ended December 31,
	2015		2014		2013
	(in thousands)
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Other expenses not allocated to reportable segments		(19,226)		(24,924)		(27,396)
Depreciation and amortization		(46,852)		(40,230)		(30,987)
Goodwill impairment		(29,896)		—		—
Interest expense		(5,375)		(8,981)		(8,245)
Loss on extinguishment of debt		—		(1,634)		—
Income tax expense		(754)		(300)		(208)
Loss on disposal of assets, net		(909)		(1,137)		(1,492)
Unit-based compensation		(1,217)		(1,658)		(790)
Total loss on commodity derivatives		(3,057)		(13,762)		902
Net cash payments for commodity derivatives settled during the period		14,821		1,071		209
Early settlement of commodity derivatives (1)		(8,745)		—		—
Corporate overhead support from general partner (2)		(5,500)		—		—
Transaction costs and other		(1,877)		(3,766)		(1,286)
Net loss from continuing operations	$	(43,705)	$	(43,748)	$	(28,196)

(1) Due to its non-recurring nature, we excluded this transaction in calculating Adjusted EBITDA.

(2) Represents expenses incurred by us that were absorbed by our general partner and not passed through to us.

Total assets from our reportable segments as of December 31 were as follows:

	December 31,		December 31,
	2015		2014
	(in thousands)
Crude oil pipelines and storage	$	408,304	$	451,518
Refined products terminals and storage		131,931		131,923
NGL distribution and sales		173,558		170,904
Corporate and other		12,092		21,958
Discontinued operations held for sale		9,374		36,870
Total assets	$	735,259	$	813,173

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Related Parties

12 Months Ended

Dec. 31, 2015

Related Party Transactions

Related Parties

17. Related Parties

We perform certain management services for JP Development. We receive a monthly fee of $50,000 for these services. The monthly fee reduced general and administrative expenses in the consolidated statements of operations by $600,000 for the years ended December 31, 2015, 2014 and 2013, respectively. In the year ended December 31, 2015, we also performed certain additional services for which we received $228,000.

JP Development had a pipeline transportation business that provides crude oil pipeline transportation services to our discontinued Mid-Continent Business. As a result of utilizing JP Development’s pipeline transportation services during the years ended December 31, 2015, 2014 and 2013, we incurred pipeline tariff fees of $6,023,000,$8,875,000 and $8,514,000, respectively, which have been included in net loss from discontinued operations in the consolidated statements of operations. Such amounts were not settled in cash during the years ended December 31, 2013, rather, they were treated as deemed contributions/distributions from/to JP Development, as discussed in Note 1. As of December 31, 2015 and 2014, we had a net receivable from JP Development of$7,933,000 and $7,968,000, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided by JP Development. We recovered these amounts in full on February 1, 2016.

As discussed in Note 11, on November 5, 2013, we issued a $1,000,000 promissory note to JP Development for working capital requirements. The note was to mature on November 5, 2016 and bore interest at 4.75%. The interest rate was subject to an adjustment each quarter equal to the weighted average rate of JP Development’s outstanding indebtedness during the most recently ended fiscal quarter. Accrued interest on the note was payable quarterly in arrears. On March 20, 2014, the Partnership repaid this promissory note in full.

As discussed in Note 13, throughout 2013, we issued 88,114 Class C Common Units to JP Development for total net proceeds of $3,128,000.  

As discussed in Note 3, on February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area to JP Development in connection with JP Development’s sale of its GSPP pipeline assets to a third party.

As discussed in Note 13, on February 12, 2014, we issued 363,636 Class A Common Units to Lonestar for total net proceeds of $8,000,000 and on March 28, 2014, we issued 1,818,182 Series D Preferred Units to Lonestar for proceeds of $40,000,000. On October 7, 2014, we paid $42,436,000 from proceeds related to our IPO to redeem all then outstanding Series D Preferred Units.

As a result of the acquisition of our North Little Rock, Arkansas refined product terminal in November 2012, Truman Arnold Companies (‘TAC”) owns common and subordinated units in us. In addition, Mr. Greg Arnold, President and CEO of TAC, is also one of our directors and owns a 5% equity interest in our general partner. Our refined products terminals and storage segment sold refined products to TAC during 2014 and 2013. For the years ended December 31, 2014 and 2013, our revenue from TAC was $8,952,000, and $14,473,000, respectively.

Our NGL distribution and sales segment also purchases refined products from TAC. In 2015 and 2014, we paid $1,124,000 and $1,964,000 for refined product purchases from TAC, which is included in cost of sales in the consolidated statements of operations. As of December 31, 2015 and 2014, we had amounts due from TAC of $40,000 and $38,000, respectively, which is included in receivables from related parties in the consolidated balance sheets.

Through April of 2015 and during all of 2014 and 2013, we entered into transactions with CAMS Bluewire, an entity in which Arclight holds a non-controlling interest. CAMS Bluewire provides IT support for us. For the years ended December 31, 2015, 2014 and 2013, we paid $132,000,  $422,000 and $691,000, respectively for IT support and consulting services, and for purchases of IT equipment, which are included in operating expenses, general and administrative expenses and property plant and equipment in the consolidated statements of operations and the consolidated balance sheets. The total amount due to CAMS Bluewire as of December 31, 2014 was $32,000.

During the third quarter of 2014, we began performing certain management services for Republic Midstream, LLC (“Republic”), an entity owned by ArcLight. We charge a monthly fee of approximately $58,000 for these services. In December 2015, this monthly fee increased to approximately $75,000. The monthly fee reduced general and administrative expenses in the consolidated statements of operations by $712,000 and $297,000 for the years ended December 31, 2015 and 2014, respectively. During the second quarter of 2015, we began performing crude transportation and marketing services for Republic. We charged $3,049,000 for the year ended December 31, 2015, for these services which is included in gathering, transportation and storage fees – related parties and crude oil sales – related parties on the consolidated statements of operations. As of December 31, 2015 and 2014, we had a receivable balance due from Republic of $646,000 and $297,000, respectively, which is included in receivables from related parties in the consolidated balance sheets.

In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In addition, ArcLight reimbursed us for expenses we incurred for the year ended December 31, 2015. The total amounts paid on our behalf or reimbursed to us were $2,568,000 for the year ended December 31, 2015, and were treated as deemed contributions from ArcLight. In addition, during the year ended December 31, 2015, our general partner agreed to absorb $5,500,000 of corporate overhead expenses incurred by us and not pass such expense through to us.

Beginning July 2013, we have no employees. The employees supporting our operations are employees of GP II, and as such, we fund GP II for payroll and other payroll-related expenses we incur. As of December 31, 2015 and 2014, we had a receivable balance due from GP II of $4,000 and $2,205,000, respectively, as a result of the timing of payroll funding, which is included in receivables from related parties in the consolidated balance sheet.

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data

18.  Selected Quarterly Financial Data (unaudited)

Selected financial data by quarter is set forth in the table below:

	Quarter Ended
	March 31,		June 30,		September 30,		December 31,
		(in thousands, except per unit data)
2015
Total revenue	$	173,291	$	199,448	$	154,641	$	153,205
Operating income (loss)		2,185		(4,204)		(5,877)		(31,412)
Income (loss) from continuing operations		1,072		(5,479)		(7,201)		(32,097)
Income (loss) from discontinued operations		(407)		542		(1,247)		(13,839)
Net income (loss)		665		(4,937)		(8,448)		(45,936)
Basic and diluted income (loss) from continuing operations per common unit		0.03		(0.15)		(0.19)		(0.88)
Basic and diluted income (loss) from continuing operations per subordinated unit		0.03		(0.15)		(0.20)		(0.88)
Basic and diluted income (loss) per common unit		0.02		(0.13)		(0.23)		(1.26)
Basic and diluted income (loss) per subordinated unit		0.02		(0.14)		(0.23)		(1.26)
2014
Total revenue	$	130,958	$	175,008	$	213,922	$	206,266
Operating loss		(3,773)		(8,540)		(4,413)		(16,115)
Loss from continuing operations		(8,475)		(10,738)		(6,410)		(18,125)
Income (loss) from discontinued operations		(113)		(9,471)		800		(491)
Net loss		(8,588)		(20,209)		(5,610)		(18,616)
Basic and diluted loss from continuing operations per common and subordinated unit		—		—		—		(0.52)
Basic and diluted loss per common and subordinated unit		—		—		—		(0.51)

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Principles of Consolidation

Principles of Consolidation.  Our consolidated financial statements have been prepared in accordance with GAAP. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

Reclassification.

Reclassification

Reclassification.  Certain previously reported amounts have been reclassified to conform to the current year presentation. For the years ended December 31, 2014 and 2013, we reclassified $9,911,000 and $1,687,000, respectively, from gathering, transportation and storage fees to crude oil sales to conform to the current year presentation.

Use of Estimates

Use of Estimates.  The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents.  We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Bank overdrafts that do not meet the right of offset criteria are recorded in capital leases and short-term debt in the consolidated balance sheets.

Restricted Cash

Restricted Cash.  Restricted cash consists of cash balances that are restricted as to withdrawal or usage and at December 31, 2014, included cash to secure crude oil production taxes payable to the applicable taxing authorities.

Accounts Receivable

Accounts Receivable.  Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the consolidated statements of operations. The allowance for doubtful accounts was $1,217,000 and $1,134,000 as of December 31, 2015 and 2014, respectively. Bad debt expense for the years ended December 31, 2015, 2014 and 2013 was $1,212,000,  $820,000 and $855,000, respectively.

Inventory

Inventory.  Inventory is mainly comprised of crude oil, NGLs, refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. Cost of crude oil, NGLs and refined products inventory is determined using the first-in, first-out (FIFO) method. Cost of propane cylinders is determined using the weighted average method.

Prepaid Expenses and Other Current Assets

Prepaid Expenses and Other Current Assets.  Prepaid expenses and other current assets primarily relate to prepaid insurance premiums, which totaled $1,239,000 and $1,044,000, and insurance claim receivables, which totaled $115,000 and $965,000 as of December 31, 2015 and 2014, respectively.

Derivatives Instruments and Hedging Activities

Derivative Instruments and Hedging Activities.  We recognize all derivative instruments as either assets or liabilities on the balance sheet at their respective fair values. We did not have any derivatives designated in hedging relationships during the years ended December 31, 2015, 2014 and 2013. Therefore, the change in the fair value of the derivative asset or liability is reflected in net loss in the consolidated statements of operations (mark-to-market accounting). Cash flows from derivatives settled are reported as cash flow from operating activities, in the same category as the cash flows from the items being economically hedged.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sales exception (“NPNS”) accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.

Property, Plant and Equipment

Property, Plant and Equipment.  Property, plant and equipment is recorded at historical cost of construction, or, upon acquisition, the fair value of the assets acquired. Repairs and maintenance costs are expensed as incurred. Any major additions and improvements that materially extend the useful lives of property, plant and equipment are capitalized. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the account, and any resulting gain or loss is recognized within the consolidated statements of operations.

We account for asset retirement obligations by recognizing on our balance sheet the net present value of any legally binding obligation to remove or remediate tangible long-lived assets, such as requirements to dispose of equipment. We record a liability for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:

Buildings	20	-	30	years
Leasehold improvements		Various*
Transportation equipment	5	-	15	years
Propane tanks and cylinders	3	-	25	years
Bulk storage tanks			20	years
Pipelines			20	years
Office furniture and fixtures	5	-	10	years
Other equipment	3	-	31	years

*Depreciated over the shorter of the life of the leasehold improvement or the lease term.

Leases

Leases.  We have both capital and operating leases. Classification is made at the inception of the lease. The classification of leases is based on the extent to which risks and rewards incidental to ownership of a leased asset lie with the lessor or the lessee.

Leased property meeting certain capital lease criteria is capitalized and the present value of the related lease payments is recorded as a liability. The present value of the minimum lease payments is calculated utilizing the lower of our incremental borrowing rate or the lessor’s interest rate implicit in the lease, if known by us. Depreciation of capitalized leased assets is computed utilizing the straight-line method over the shorter of the estimated useful life of the asset or the lease term and is included in depreciation and amortization in our consolidated statements of operations. However, if the lease meets the bargain purchase or transfer of ownership criteria, the asset shall be amortized in accordance with our normal depreciation policy for owned assets.

Minimum rent payments under operating leases are recognized as an expense on a straight-line basis over the lease term, including any rent free periods.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets.  Long-lived assets such as property, plant and equipment, and acquired intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary (Level 3). For assets held for sale, we compare the fair value of the disposal group to its carrying value. Under the assets held for sale criteria, the order of impairment is based on (i) testing other assets, such as accounts receivable, inventory and indefinite-lived intangible assets, for impairment (ii) testing goodwill for impairment and (iii) testing the long-lived asset group for impairment. In connection with the sale of our Mid-Continent Business (defined in Note 3 and classified as held for sale at December 31, 2015), we recorded an impairment charge of $4,970,000 during the year ended December 31, 2015 related to long-lived assets, which is classified in net loss from discontinued operations in the consolidated statements of operations.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets.We apply Accounting Standards Codification ("ASC") 805, "Business Combinations," and ASC 350, "Intangibles—Goodwill and Other," to account for goodwill. In accordance with these standards, goodwill is not amortized but is tested for impairment at least annually, or more frequently whenever a triggering event or change in circumstances occurs at the reporting unit level. A reporting unit is the operating segment, or business one level below the operating segment if discrete financial information is prepared and regularly reviewed by segment management. We have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.

In 2015, we recognized impairment charges of $23,574,000 and $6,322,000 related to the goodwill in our crude oil supply and logistics reporting unit within our crude oil pipelines and storage segment and JP Liquids reporting unit within our NGL distribution and sales segment, respectively, primarily due to the substantial decline in commodity prices in 2015 and the resulting decline in margin as well as volume in those reporting units.  We also recorded an additional goodwill impairment charge of $7,939,000 triggered by the disposition of our Mid-Continent Business. The $7,939,000 of goodwill was allocated to the Mid-Continent Business based on the relative fair value of the Mid-Continent Business and the portion of the reporting unit that was retained by us. No provision for impairment of goodwill was recorded during 2014 or 2013.

During the second quarter of 2014, immediately prior to the sale of the Bakken Business (defined in Note 3) within the crude oil supply and logistics reporting unit, we allocated $1,984,000 of goodwill to the Bakken Business, which was based on the relative fair value of the disposed Bakken Business and the portion of the reporting unit that was retained by us. The $1,984,000 allocation contributed to the overall net loss from discontinued operations.

Business Combinations

Business Combinations.  When a business is acquired, we allocate the purchase price to the various components of the acquisition based upon the fair value of each component using various valuation techniques, including the market approach, income approach and/or cost approach. The accounting standard for business combinations requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired to be recorded at fair value. Transaction costs related to the acquisition of the business are expensed as incurred. Costs associated with the issuance of debt associated with a business combination are capitalized and included as a yield adjustment to the underlying debt’s stated rate. Acquired intangible assets other than goodwill are amortized over their estimated useful lives unless the lives are determined to be indefinite. Contingent consideration obligations are recorded at fair value on the date of acquisition, with increases or decreases in the fair value arising from changes in assumptions or discount periods recorded as contingent consideration expenses in the consolidated statement of operations in subsequent periods. The fair values assigned to tangible and intangible assets acquired and liabilities assumed, including contingent consideration, are based on management’s estimates and assumptions, as well as other information compiled by management, including valuations that utilize customary valuation procedures and techniques.

When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated similar to the pooling of interest method of accounting. Under a common control acquisition, the assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

Deferred Financing Costs

Deferred Financing Costs.  Debt issuance costs related to our revolving credit agreement (see Note 11) are deferred and are recorded net of accumulated amortization in the consolidated balance sheets as deferred financing costs, and totaled $2,809,000 and $3,712,000 at December 31, 2015 and 2014, respectively. These costs are amortized over the terms of the related debt using the effective interest rate method for the notes payable and the straight-line method for the revolving credit facilities. As a result of the financing transactions discussed in Note 11, we wrote off $1,634,000 of deferred financing costs associated with the extinguishment of debt during the year ended December 31, 2014 which is recorded in loss on extinguishment of debt in the consolidated statements of operations. Amortization of deferred financing costs is recorded in interest expense and totaled $909,000,  $906,000 and $1,103,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Customer Deposits and Advances

Customer Deposits and Advances.  Certain customers are offered a prepayment program which requires a customer to pay a fixed periodic amount or to otherwise prepay a portion of their anticipated product purchases. Customer prepayments in excess of associated billings are classified as customer deposits and advances in the consolidated balance sheets.

Revenue Recognition

Revenue Recognition.  We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller’s price to the buyer is fixed and determinable and collectability is reasonably assured.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the consolidated statements of operations.

Crude Oil Pipelines and Storage.  The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. For certain crude oil pipeline transportation arrangements, we enter into sale and purchase contracts with counterparties instead of pipeline transportation agreements. In such cases, we assess the indicators associated with agent and principal considerations for each arrangement to determine whether revenue should be recorded on a gross basis versus net basis. In addition, we also provide crude oil transportation services to third party customers.

Refined Products Terminals and Storage.  We generate fee-based revenues for terminal and storage services with longstanding customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Such fee-based revenues are recognized when services are proved upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

NGLs Distributions and Sales.  Revenues from the NGLs distributions and sales are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees.

Operating expenses

Operating expenses.  Operating expenses primarily include personnel, vehicle, delivery, handling, office, selling, and other expenses related to the distribution, terminal and storage of products and related supplies.

Expenses associated with the delivery of products to customers (including vehicle expenses, expenses of delivery personnel and vehicle repair and maintenance) are classified as operating expenses in the consolidated statements of operations.

General and administrative expenses

General and administrative expenses.  General and administrative expenses primarily include wages and benefits and department related costs for human resources, legal, finance and accounting, administrative support and supply.

Fair value measurement

Fair value measurement.  We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. We determine fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The fair value of our derivatives (see Note 12) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The fair value of our contingent liabilities (see Note 5) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). We do not have any other assets or liabilities measured at fair value on a recurring basis.

Our other financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and long term debt. The carrying value of our trade and other receivables, accounts payable and accrued expenses approximates fair value due to their highly liquid nature, short term maturity, or competitive rates assigned to these financial instruments. The fair value of long-term debt approximates the carrying value as the underlying instruments bear interest at rates similar to current rates offered to us for debt with the same remaining maturities.

Concentration Risk

Concentration Risk.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have not experienced any losses related to these balances.

The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues from transactions with an external customer amounting to 10% or more of revenue are disclosed below, together with the identity of the reportable segment.

		Year Ended December 31,
Customer	ReportableSegment	2015	2014	2013
		(inthousands)
Customer A	Crudeoil pipelines and storage, NGLs distribution and sales	252,969	164,115	*
Customer B	Crudeoil pipelines and storage, Refined products terminals and storage	*	90,923	48,544

* Revenues are less than 10% of the total revenues during the period.

We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

Income Taxes

Income Taxes.  We are a limited partnership, and therefore not directly subject to federal income taxes or most state income taxes. Our taxable income (loss) will be included in the federal income tax returns filed by the individual partners. Accordingly, no federal income tax provision has been made in our consolidated financial statements since the income tax is an obligation of the partners. We are subject to the Texas margin tax, which is reported in income tax expense in the consolidated statements of operations.

ASC 740, “Income Taxes”, requires the evaluation of tax positions taken or expected to be taken in the course of preparing our state tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe we have any tax positions taken within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions as part of our income tax expense, when and if they become applicable.

Equity-Based Compensation

Equity-Based Compensation.  We account for equity based compensation by recognizing the fair value of awards on the grant date or the date of modification, as applicable, into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required.

Comprehensive Loss

Comprehensive Loss.  For the years ended December 31, 2015, 2014 and 2013, comprehensive loss was equal to net loss.

Recent Accounting Pronouncements

Recent Accounting Pronouncements.  In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 requires equity investments to be measured at fair value with changes in fair value recognized in net income; simplifies the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; requires an entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; requires separate presentation of financial assets and financial liabilities by measurement category and form of financial assets on the balance sheet or the accompanying notes to the financial statements and clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. This standard does not allow for early adoption except related to credit risk adjustment in other comprehensive income. The adoption of ASU 2016-01 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This ASU is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early application permitted and, upon adoption, may be applied either prospectively or retrospectively. We early adopted, retrospectively, ASU 2015-17. There is no impact from the adoption of this ASU as our deferred taxes are already presented under the non-current classification for all periods presented.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). ASU 2015-16 changes how the acquirer recognizes adjustments to the provisional amounts of a business combination that are identified during the measurement period  from a retrospective application of all affected financial periods to be recorded in the reporting period in which the adjustment amounts are determined. Additionally, the company needs to disclose, of the amounts recorded in current periods, what amounts would have been reported in previous periods if the adjustments had been recognized at the acquisition date.  ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015.  Early adoption of this ASU is permitted. The adoption of ASU 2015-16 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). ASU 2015-15 provides SEC Staff guidance to ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost, as it relates to debt issuance cost associated with line-of-credit arrangements. The SEC staff recognized that ASU 2015-03 did not address presentation or subsequent measurement of debt issuances cost related to line-of-credit arrangements and noted that the SEC Staff wouldn’t object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings of the line-of credit arrangement. ASU 2015-15 was adopted in the third quarter of 2015 with ASU 2015-03 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

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

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

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

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

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

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

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Estimated useful lives of property, plant and equipment

Buildings	20	-	30	years
Leasehold improvements		Various*
Transportation equipment	5	-	15	years
Propane tanks and cylinders	3	-	25	years
Bulk storage tanks			20	years
Pipelines			20	years
Office furniture and fixtures	5	-	10	years
Other equipment	3	-	31	years

*Depreciated over the shorter of the life of the leasehold improvement or the lease term.

Revenues from transactions with an external customer amounting to 10% or more of revenue

		Year Ended December 31,
Customer	ReportableSegment	2015	2014	2013
		(inthousands)
Customer A	Crudeoil pipelines and storage, NGLs distribution and sales	252,969	164,115	*
Customer B	Crudeoil pipelines and storage, Refined products terminals and storage	*	90,923	48,544

* Revenues are less than 10% of the total revenues during the period.

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2015

Mid-Continent Business

Summary of selected financial information related to discontinued operations

Consolidated Statements of Operations

The discontinued operations of the Mid-Continent Business are summarized below:

	Year Ended December 31,
	2015		2014		2013
	(in thousands, except unit and per unit data)
REVENUES
Crude oil sales	$	429,716	$	967,359	$	1,711,036
Gathering, transportation and storage fees		16		31		204
Other revenues		52		90		124
Total revenues		429,784		967,480		1,711,364
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		426,886		961,428		1,687,827
Operating expense		1,402		1,930		4,197
General and administrative		867		936		996
Impairment of goodwill and assets held for sale		12,909		—		—
Depreciation and amortization		2,281		2,258		2,358
Loss on disposal of assets, net		119		229		—
Total costs and expenses		444,464		966,781		1,695,378
OPERATING INCOME (LOSS)		(14,680)		699		15,986
OTHER INCOME (EXPENSE)
Interest expense		(296)		(412)		(830)
Loss on extinguishment of debt		—		—		—
Other income, net		25		46		1
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES		(14,951)		333		15,157
Income tax (expense) benefit		—		—		—
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	(14,951)	$	333	$	15,157

Consolidated Balance Sheets

The current and non-current assets and liabilities of the Mid-Continent Business are as follows:

	December 31,		December 31,
	2015		2014
	(in thousands)
ASSETS
Current assets
Inventory	$	2,692	$	15,149
Prepaid expenses and other current assets		38		—
Total Current assets of discontinued operations held for sale		2,730		15,149
Non-current assets
Property, plant and equipment, net		5,203		10,458
Goodwill		—		7,939
Intangible assets, net		1,138		2,981
Deferred financing costs and other assets, net		303		343
Total Non-current assets of discontinued operations held for sale		6,644		21,721
Total Assets of discontinued operations held for sale	$	9,374	$	36,870
LIABILITIES
Current liabilities
Accrued liabilities	$	640	$	—
Total Current liabilities of discontinued operations held for sale	$	640	$	—

The following table summarizes other selected financial information related to the Mid-Continent Business.

	Year Ended December 31,
	2015		2014		2013
	(in thousands)
Depreciation	$	1,127	$	1,104	$	1,204
Amortization		1,154		1,154		1,154
Capital expenditures		637		316		1,327
Other operating noncash items related to discontinued operations:
Impairment on goodwill and assets held for sale	$	12,909	$	—	$	—
Derivative valuation changes		630		—		—
Loss on disposal of assets		119		229		—
Non-cash inventory LCM adjustments		—		222		—
Investing noncash items related to discontinued operations:
Accrued capital expenditures	$	—	$	218	$	—

Bakken Business

Summary of selected financial information related to discontinued operations

		Year Ended December 31,
		2014		2013
	(in thousands)
Revenues from discontinued operations	$	7,865	$	19,283
Net loss of discontinued operations, including loss on disposal of $7,288 in 2014		(9,608)		(1,182)

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Net Loss Per Unit (Tables)

12 Months Ended

Dec. 31, 2015

Net Loss Per Unit

Schedule of basic and diluted net loss per unit

	Year ended December 31, 2015
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	24,172	$	23,571	$	47,743
Distributions in excess of net income		(46,002)		(45,446)		(91,448)
Net loss from continuing operations attributable to the limited partners	$	(21,830)	$	(21,875)	$	(43,705)
Net loss from discontinued operations attributable to the limited partners		(7,521)		(7,430)		(14,951)
Net loss attributable to the limited partners	$	(29,351)	$	(29,305)	$	(58,656)
Weighted average units outstanding:
Basic		18,373,594		18,151,700		36,525,294
Net loss per unit:
Basic and diluted from continuing operations	$	(1.19)	$	(1.20)
Basic and diluted from discontinued operations	$	(0.41)	$	(0.41)
Basic and diluted total	$	(1.60)	$	(1.61)

	Year ended December 31, 2014
	Common Units		Subordinated Units		Total
		(inthousandsexceptfor unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	5,523	$	5,491	$	11,014
Distributions in excess of net income		(14,983)		(14,981)		(29,964)
Net loss from continuing operations attributable to the limited partners	$	(9,460)	$	(9,490)	$	(18,950)
Net income from discontinued operations attributable to the limited partners		167		167		334
Net loss attributable to the limited partners	$	(9,293)	$	(9,323)	$	(18,616)
Weighted average units outstanding:
Basic		18,212,632		18,209,948		36,422,580
Net income (loss) per unit:
Basic and diluted from continuing operations	$	(0.52)	$	(0.52)
Basic and diluted from discontinued operations	$	0.01	$	0.01
Basic and diluted total	$	(0.51)	$	(0.51)

Schedule of antidilutive securities excluded from computation of diluted earnings per unit

Phantom units 406,218

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Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2015

Acquisitions

Pro Forma Information

	Year ended December 31, 2013
	(inthousands)
	(unaudited)
Pro forma consolidated revenue from continuing operations	$	393,837
Pro forma consolidated net loss from continuing operations	$	(32,501)

Southern Propane Member

Acquisitions

Schedule of purchase price allocation

The following table represents our allocation of the total purchase price of this acquisition to the assets acquired (in thousands):

Accounts receivable	$	932
Inventory		24
Total current assets		956
Property, plant and equipment		2,962
Intangible assets:
Customer relationships		6,163
Noncompete agreements		292
Trade names		113
Total identifiable net assets acquired		10,486
Goodwill		5,806
Net assets acquired	$	16,292

Wildcat Permian Service LLC

Acquisitions

Schedule of purchase price allocation

The following table represents the allocation of the total purchase price of this acquisition to the assets acquired and liabilities assumed on October 7, 2013 (in thousands):

Cash	$	2,570
Accounts receivable		16,068
Inventory		283
Short-term prepaid asset		134
Total current assets		19,055
Property, plant and equipment		33,962
Long-term prepaid asset		951
Intangible assets:
Customer relationships		67,700
Total assets acquired		121,668
Total liabilities assumed		(17,227)
Total identifiable net assets acquired		104,441
Goodwill		108,363
Net assets acquired	$	212,804

Other 2013 Acquisitions

Acquisitions

Schedule of purchase price allocation

The following table represents the allocation of the aggregated purchase price to the assets acquired related to the three acquisitions described above, which are individually insignificant at their respective original acquisition dates by JP Development (in thousands):

Accounts receivable	$	504
Inventory		15
Total current assets		519
Property, plant and equipment		8,503
Intangible assets:
Trade names and trademarks		286
Customer relationships		8,022
Noncompete agreements		429
Total assets acquired		17,759
Total liabilities assumed		(475)
Total identifiable net assets acquired		17,284
Goodwill		9,764
Net assets acquired	$	27,048

Summary of other acquisitions

Dateof acquisition	Name of acquired entity	Totalpurchaseprice
		(inthousands)
July 15, 2013	BMHPropane, LLC (d/b/a Valley Gas)	$	2,437
August 30, 2013	Alexander Oil Field Service, Inc.		7,792
October 11, 2013	Highway Pipeline, Inc.		16,819

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Inventory (Tables)

12 Months Ended

Dec. 31, 2015

Inventory

Schedule of inventory

	December 31,
	2015		2014
	(in thousands)
Crude Oil	$	338	$	162
NGLs		2,364		3,342
Refined Products		430		445
Materials, supplies and equipment		1,654		1,728
Total inventory	$	4,786	$	5,677

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Property, Plant and Equipment, net (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment, net

Schedule of property, plant and equipment, net

	December 31,
	2015		2014
	(in thousands)
Land	$	6,874	$	6,874
Buildings and improvements		12,561		12,045
Transportation equipment		46,582		39,388
Storage and propane tanks		151,988		139,721
Pipelines and linefill		77,295		54,059
Office furniture and fixtures		9,701		8,245
Other equipment		48,171		25,892
Construction-in-progress		12,763		15,175
Total property, plant and equipment		365,935		301,399
Less: accumulated depreciation		(74,481)		(49,709)
Property, plant and equipment, net	$	291,454	$	251,690

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets

Schedule of intangible assets

	December 31, 2015
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
		(in thousands)
Customer relationships	$	82,630	$	(20,761)	$	61,869
Noncompete agreements		3,575		(2,664)		911
Trade names		553		(139)		414
Customer contract		95,594		(24,538)		71,056
Other		198		(16)		182
Total	$	182,550	$	(48,118)	$	134,432
	December 31, 2014
	Gross				Net
	carrying		Accumulated		carrying
	amount		amortization		amount
	(in thousands)
Customer relationships	$	76,466	$	(14,275)	$	62,191
Noncompete agreements		3,728		(2,283)		1,445
Trade names		2,147		(583)		1,564
Customer contract		95,594		(15,662)		79,932
Other		209		(11)		198
Total	$	178,144	$	(32,814)	$	145,330

Schedule of estimated future amortization expense for amortizable intangible assets

The estimated future amortization expense for amortizable intangible assets to be recognized is as follows (in thousands):

2016	$	16,163
2017		15,754
2018		15,484
2019		13,499
2020		10,790
Thereafter		62,742
Total	$	134,432

Schedule of goodwill activity

			Refined
	Crude oil		products		NGL
	pipelines and		terminals and		distribution
	storage		storage		and sales		Total
	(in thousands)
Balance at January 1, 2014	$	150,268	$	61,163	$	31,335	$	242,766
Disposals		(1,984)		—		—		(1,984)
Balance at December 31, 2014		148,284		61,163		31,335		240,782
Goodwill acquired during the year		—		—		5,806		5,806
Goodwill impairment		(23,574)		—		(6,322)		(29,896)
Balance at December 31, 2015	$	124,710	$	61,163	$	30,819	$	216,692

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Accrued Liabilities

Schedule of accrued liabilities

	December 31,
	2015		2014
	(inthousands)
Taxes payable	$	1,204	$	1,915
Accrued payroll and employee benefits		4,756		8,148
Accrued professional fees		696		462
Royalties payable		4,163		4,281
Short-term derivative liabilities		358		10,157
Other		4,083		4,008
Total accrued liabilities	$	15,260	$	28,971

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Capital Leases and Other Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Capital Leases and Other Short-Term Debt

Schedule of assets held under capital lease agreements

	December 31,
	2015		2014
	(inthousands)
Buildings and improvements	$	16	$	138
Transportation equipment		167		261
Office furniture and equipment		133		129
Other equipment		35		49
		351		577
Less: Accumulated depreciation		(197)		(254)
Assets under capital lease, net	$	154	$	323

Scheduled principal repayments of capital lease obligations

Scheduled repayments of capital lease obligations are as follows (in thousands):

Years ending December 31,
2016	$	153
2017		116
2018		40
2019		31
2020		22
Thereafter		11
		373
Less: amounts representing interest		(137)
Total obligations under capital leases		236
Less: current portion		(107)
Long-term capital lease obligation	$	129

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Long-Term Debt

Schedule of long-term debt

	December 31,
	2015		2014
	(in thousands)
Bank of America revolving loan	$	162,000	$	83,000
HBH note payable		1,077		1,277
Non-compete notes payable		117		231
Total long-term debt	$	163,194	$	84,508
Less: Current maturities		(454)		(383)
Total long-term debt, net of current maturities	$	162,740	$	84,125

Scheduled principal repayments of long-term debt

Scheduled principal repayments of long-term debt for each of the next five years ending December 31 and thereafter are as follows (in thousands):

2016	$	454
2017		740
2018		—
2019		162,000
2020		—
Thereafter		—
Total	$	163,194

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Summary of fair values of derivative contracts included in the condensed consolidated balance sheets

		Asset Derivatives				Liability Derivatives
		December 31,		December 31,		December 31,		December 31,
	Balance Sheet Location	2015		2014		2015		2014
		(in thousands)
Commodity swaps	Prepaid expenses and other current assets	$	92	$	—	$	—	$	—
Commodity swaps	Accrued liabilities		—		—		(450)		(8,941)
Commodity swaps	Other long-term liabilities		—		—		(24)		(3,251)
Interest rate swaps	Accrued Liabilities		—		—		—		(158)

Schedule presents the fair value of recognized current derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheet that are subject to enforceable master netting arrangements

	As of December 31, 2015
	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented in the Balance Sheet		Financial Collateral		Net Amount
	(in thousands)
Derivative Assets:
Derivative contracts - current	$	92	$	(92)	$	—	$	—	$	—
Derivative contracts - noncurrent		—		—		—		—		—
Derivative Liabilities:
Derivative contracts - current	$	450	$	(92)	$	358	$	—	$	358
Derivative contracts - noncurrent		24		—		24		—		24

Summary of amounts recognized with respect to derivative instruments within the condensed consolidated statements of operations

	Location of Gain (Loss) Recognized in	Amount of Gain/(Loss) Recognized in Income on Derivatives
	Income on Derivatives	December 31, 2015		December 31, 2014		December 31, 2013
		(in thousands)
Commodity derivatives (swaps)	Cost of sales		(3,056)		(13,762)		902
Interest rate swaps	Interest expense		(27)		(227)		(168)

Commodity swap contracts

Schedule of notional values of outstanding derivatives

	December 31, 2015		December 31, 2014
	NotionalVolume	Maturity	Notional Volume	Maturity
Fixed Price Swaps :
Propane (Gallons)	8,614,631	Jan 2016 - July 2017	27,958,302	Jan 2015 - Dec 2016
Crude Oil (Barrels)	(93,000)	Jan 2016	—	—

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2015

Partners' Capital

Schedule of distributions paid to existing unit holders

	Cash Distribution
Distribution Date	(per unit)
February 2013	$	0.5000
July 2013		0.5000
August 2013		0.5000
February 2015		0.3038	(1)
May 2015		0.3250
August 2015		0.3250
November 2015		0.3250

Schedule of inputs used to estimate fair value of the Class B and Class C common units

	December 31, 2013					April 19, 2013
WACC	10.71	%	-	11.21	%	9.41	%	-	9.91	%
Market multiple	12.05		-	12.55	times	10.5		-	11	times

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Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Phantom Share Units (PSUs)

Unit-Based Compensation

Summary of restricted (non vested) common units

Phantom Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	—	$	—
Service condition grants	497,479		12.84
Vested service condition	(8,250)		12.90
Forfeited service condition	(96,809)		12.26
Outstanding at the end of period	392,420		12.99

Restricted Stock Units (RSUs)

Unit-Based Compensation

Summary of restricted (non vested) common units

2015
	Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	31,012	$	24.36	126,553	$	24.36
Vested - service condition	(10,512)		25.37	(42,898)		25.37
Forfeited - service condition	(14,076)		22.89	(57,439)		22.89
Outstanding at the end of period	6,424		25.91	26,216		25.91

2014
	Class B Common Units			Common Units			Subordinated Units
Restricted(Non‑Vested)Units	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	177,867	$	25.58	—	$	—	—	$	—
Granted - service condition	90,000		19.64	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	(63,698)		24.21	—		—	—		—
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	(6,667)		34.91	—		—	—		—
Forfeited - performance condition	—		—	—		—	—		—
Conversion upon IPO	(197,502)		23.00	34,603		25.84	141,211		25.84
Granted - service condition	—		—	—		—	—		—
Granted - performance condition	—		—	—		—	—		—
Vested - service condition	—		—	(876)		36.75	(3,576)		36.75
Vested - performance condition	—		—	—		—	—		—
Forfeited - service condition	—		—	(2,715)		39.22	(11,082)		39.22
Forfeited - performance condition	—		—	—		—	—		—
Outstanding at the end of period	—		—	31,012		24.36	126,553		24.36

8
2013
Restricted (Non-Vested) Common Units	Units	Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	143,000	$	20.32
Granted - service condition	68,500		34.91
Granted - performance condition	—		—
Vested - service condition	(23,633)		23.37
Vested - performance condition	—		—
Forfeited - service condition	(10,000)		19.51
Forfeited - performance condition	—		—
Outstanding at the end of period	177,867		25.58

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Commitments and Contingencies (Table)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Minimum future payments under non-cancelable operating leases as of December 31, 2015 and thereafter are as follows (in thousands):

2016	$	5,116
2017		4,331
2018		3,776
2019		2,383
2020		718
Thereafter		4,877
	$	21,201

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Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2015

Reportable Segments

Schedule of financial data for each reportable segment

	Year ended December 31,
	2015		2014		2013
	(in thousands)
External Revenues:
Crude oil pipelines and storage	$	480,527	$	495,971	$	186,993
Refined products terminals and storage		23,227		23,287		24,011
NGL distribution and sales		176,831		206,896		179,865
Total revenues	$	680,585	$	726,154	$	390,869
Cost of Sales, excluding depreciation and amortization:
Crude oil pipelines and storage	$	445,027	$	459,183	$	167,744
Refined products terminals and storage		8,649		6,453		4,683
NGL distribution and sales		76,618		126,686		105,488
Amounts not included in segment Adjusted EBITDA		(2,818)		13,360		(1,111)
Total cost of sales, excluding depreciation and amortization	$	527,476	$	605,682	$	276,804
Operating Expenses:
Crude oil pipelines and storage	$	9,238	$	7,928	$	7,405
Refined products terminals and storage		2,980		4,602		2,464
NGL distribution and sales		57,200		52,109		47,307
Amounts not included in segment Adjusted EBITDA		(41)		945		552
Total operating expenses	$	69,377	$	65,584	$	57,728
Depreciation and Amortization:
Crude oil pipelines and storage	$	20,356	$	17,240	$	10,335
Refined products terminals and storage		6,830		5,911		6,162
NGLs distribution and sales		18,628		16,163		13,981
Corporate and other		1,038		916		509
Total depreciation and amortization	$	46,852	$	40,230	$	30,987
Adjusted EBITDA:
Crude oil pipelines and storage	$	23,119	$	25,339	$	9,479
Refined products terminals and storage		10,867		10,723		16,100
NGL distribution and sales		30,896		15,511		15,518
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Capital Expenditures:
Crude oil pipelines and storage	$	42,919	$	36,691	$	4,410
Refined products terminals and storage		8,002		2,489		4,482
NGLs distribution and sales		18,587		16,557		16,009
Corporate and other		1,503		1,141		1,927
Total capital expenditures	$	71,011	$	56,878	$	26,828

Schedule of reconciliation of total Adjusted EBITDA from reportable segments to net income (loss) from continuing operations

	Year ended December 31,
	2015		2014		2013
	(in thousands)
Total adjusted EBITDA from reportable segments	$	64,882	$	51,573	$	41,097
Other expenses not allocated to reportable segments		(19,226)		(24,924)		(27,396)
Depreciation and amortization		(46,852)		(40,230)		(30,987)
Goodwill impairment		(29,896)		—		—
Interest expense		(5,375)		(8,981)		(8,245)
Loss on extinguishment of debt		—		(1,634)		—
Income tax expense		(754)		(300)		(208)
Loss on disposal of assets, net		(909)		(1,137)		(1,492)
Unit-based compensation		(1,217)		(1,658)		(790)
Total loss on commodity derivatives		(3,057)		(13,762)		902
Net cash payments for commodity derivatives settled during the period		14,821		1,071		209
Early settlement of commodity derivatives (1)		(8,745)		—		—
Corporate overhead support from general partner (2)		(5,500)		—		—
Transaction costs and other		(1,877)		(3,766)		(1,286)
Net loss from continuing operations	$	(43,705)	$	(43,748)	$	(28,196)

(1) Due to its non-recurring nature, we excluded this transaction in calculating Adjusted EBITDA.

(2) Represents expenses incurred by us that were absorbed by our general partner and not passed through to us.

Schedule of total assets from reportable segments

	December 31,		December 31,
	2015		2014
	(in thousands)
Crude oil pipelines and storage	$	408,304	$	451,518
Refined products terminals and storage		131,931		131,923
NGL distribution and sales		173,558		170,904
Corporate and other		12,092		21,958
Discontinued operations held for sale		9,374		36,870
Total assets	$	735,259	$	813,173

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of selected financial data by quarter

	Quarter Ended
	March 31,		June 30,		September 30,		December 31,
		(in thousands, except per unit data)
2015
Total revenue	$	173,291	$	199,448	$	154,641	$	153,205
Operating income (loss)		2,185		(4,204)		(5,877)		(31,412)
Income (loss) from continuing operations		1,072		(5,479)		(7,201)		(32,097)
Income (loss) from discontinued operations		(407)		542		(1,247)		(13,839)
Net income (loss)		665		(4,937)		(8,448)		(45,936)
Basic and diluted income (loss) from continuing operations per common unit		0.03		(0.15)		(0.19)		(0.88)
Basic and diluted income (loss) from continuing operations per subordinated unit		0.03		(0.15)		(0.20)		(0.88)
Basic and diluted income (loss) per common unit		0.02		(0.13)		(0.23)		(1.26)
Basic and diluted income (loss) per subordinated unit		0.02		(0.14)		(0.23)		(1.26)
2014
Total revenue	$	130,958	$	175,008	$	213,922	$	206,266
Operating loss		(3,773)		(8,540)		(4,413)		(16,115)
Loss from continuing operations		(8,475)		(10,738)		(6,410)		(18,125)
Income (loss) from discontinued operations		(113)		(9,471)		800		(491)
Net loss		(8,588)		(20,209)		(5,610)		(18,616)
Basic and diluted loss from continuing operations per common and subordinated unit		—		—		—		(0.52)
Basic and diluted loss per common and subordinated unit		—		—		—		(0.51)

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Business and Basis of Presentation (Details) - USD ($) $ in Millions		12 Months Ended
	Feb. 12, 2014	Dec. 31, 2014
Business and Basis of Presentation
Units issued		12,561,934
Class A Common Unit | Limited
Business and Basis of Presentation
Units issued		12,561,934
Common Control Acquisition | JP Development
Business and Basis of Presentation
Aggregate Purchase price	$ 319.1
Cash price	52.0
Common Control Acquisition | JP Development | General Partner
Business and Basis of Presentation
Deemed distribution	$ 12.7
Common Control Acquisition | JP Development | Class A Common Unit | Limited
Business and Basis of Presentation
Units issued	12,561,934

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Business and Basis of Presentation (IPO) (Details)			12 Months Ended
	Oct. 07, 2014 USD ($) $ / shares shares	Oct. 07, 2014 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($)
Business and Basis of Presentation
Distribution of accounts receivable		$ 92,100,000
Units of ownership interest in partnership | shares			18,465,320	18,209,519
Number of general partner units recharacterized as non-economic general partner interest | shares		45
Proceeds from IPO		$ 257,100,000
Offering expenses		2,000,000
Amount of redemption of preferred units				$ 42,436,000
Repayment of debt outstanding			$ 375,000	4,870,000	$ 4,152,000
Increase (decrease) in working capital of the Partnership		17,100,000
Amount borrowed in order to replenish working capital			$ 130,000,000	$ 390,800,000	$ 32,300,000
Acquisition revolving credit facility
Business and Basis of Presentation
Repayment of debt outstanding		195,600,000
Amount borrowed in order to replenish working capital		$ 75,000,000
Series D Preferred Unit
Business and Basis of Presentation
Percentage of preferred units redeemed		100.00%
Amount of redemption of preferred units	$ 42,436,000
Lonestar
Business and Basis of Presentation
Distribution of accounts receivable		$ 72,500,000
TAC
Business and Basis of Presentation
Distribution of accounts receivable		6,000,000
JP Development
Business and Basis of Presentation
Distribution of accounts receivable		$ 3,300,000
IPO
Business and Basis of Presentation
Period after end of each quarter, within which available cash to be distributed to unitholders of record on the applicable record date, subject to certain terms and conditions		45 days
Common | IPO
Business and Basis of Presentation
Number of common units issued to the public | shares	13,750,000	13,750,000
Per unit price of common units issued to the public | $ / shares	$ 20.00
Percentage of ownership interest in partnership	37.70%	37.70%
Proceeds from IPO	$ 257,100,000
Prior to the closing of the IPO | Existing Common Units
Business and Basis of Presentation
Unit split ratio		0.89		0.89
Number of common units resulting from unit split | shares		22,677,004
Conversion of units (in units) | shares		(18,213,502)
Percentage of ownership interest in partnership		19.70%		80.30%
Units of ownership interest in partnership | shares	4,463,502	4,463,502
Prior to the closing of the IPO | Subordinated
Business and Basis of Presentation
Conversion of units (in units) | shares		18,213,502
Percentage of ownership interest in partnership		80.30%		19.70%
After the closing of the IPO | Existing Common Units
Business and Basis of Presentation
Conversion of units (in units) | shares		(4,463,502)
Common units conversion ratio		1
After the closing of the IPO | Subordinated
Business and Basis of Presentation
Percentage of ownership interest in partnership		50.00%
After the closing of the IPO | Common | Existing partners
Business and Basis of Presentation
Conversion of units (in units) | shares		4,463,502
Percentage of ownership interest in partnership		12.30%

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Summary of Significant Accounting Policies (Reclassification) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounts Receivable
Accounts receivable, allowance for doubtful accounts	$ 1,217,000	$ 1,134,000
Bad debt expense	1,212,000	820,000	$ 855,000
Prepaid Expenses and Other Current Assets
Prepaid insurance premiums	1,239,000	1,044,000
Insurance claim receivables	$ 115,000	965,000
Crude oil pipelines and storage
Reclassification
Crude Oil Sales Revenue Reclassified From Gathering Transportation And Storage Fees		$ 9,911,000	$ 1,687,000

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Summary of Significant Accounting Policies (PP&E) (Details)	12 Months Ended
	Dec. 31, 2015
Buildings | Minimum
Property, Plant and Equipment, net
Estimated useful lives	20 years
Buildings | Maximum
Property, Plant and Equipment, net
Estimated useful lives	30 years
Transportation equipment | Minimum
Property, Plant and Equipment, net
Estimated useful lives	5 years
Transportation equipment | Maximum
Property, Plant and Equipment, net
Estimated useful lives	15 years
Propane tanks and cylinders | Minimum
Property, Plant and Equipment, net
Estimated useful lives	3 years
Propane tanks and cylinders | Maximum
Property, Plant and Equipment, net
Estimated useful lives	25 years
Bulk storage tanks | Maximum
Property, Plant and Equipment, net
Estimated useful lives	20 years
Pipelines and linefill | Maximum
Property, Plant and Equipment, net
Estimated useful lives	20 years
Office furniture and fixtures | Minimum
Property, Plant and Equipment, net
Estimated useful lives	5 years
Office furniture and fixtures | Maximum
Property, Plant and Equipment, net
Estimated useful lives	10 years
Other equipment | Minimum
Property, Plant and Equipment, net
Estimated useful lives	3 years
Other equipment | Maximum
Property, Plant and Equipment, net
Estimated useful lives	31 years

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Summary of Significant Accounting Policies (Long-lived Assets) (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)
Held-for-sale | Mid-Continent Business
Impairment of Long-Lived Assets
Asset impairment	$ 4,970,000

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Summary of Significant Accounting Policies (Goodwill and Other Intangibles) (Details) - USD ($)	12 Months Ended		24 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Goodwill
Impairment loss	$ 29,896,000		$ 0
Goodwill allocated to discontinued operations	216,692,000	$ 240,782,000	240,782,000		$ 242,766,000
Goodwill written off		1,984,000
NGL distribution and sales | JP Liquids
Goodwill
Impairment loss	6,322,000
Crude oil pipelines and storage
Goodwill
Impairment loss	23,574,000
Goodwill allocated to discontinued operations	124,710,000	148,284,000	$ 148,284,000		$ 150,268,000
Goodwill written off		1,984,000
Crude oil pipelines and storage | Crude Oil Supply and Logistics
Goodwill
Impairment loss	23,574,000
Held-for-sale | Mid-Continent Business
Goodwill
Impairment loss	7,939,000
Goodwill allocated to discontinued operations	$ 7,939,000
Disposed of by Sale | Bakken Business
Goodwill
Goodwill allocated to discontinued operations				$ 1,984,000
Goodwill written off		$ 1,984,000

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Summary of Significant Accounting Policies (Deferred Financing Costs) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred Financing Costs
Debt issuance costs, net	$ 2,809,000	$ 3,712,000
Loss on extinguishment of debt		1,634,000
Amortization of deferred financing costs	$ 909,000	$ 906,000	$ 1,103,000

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Summary of Significant Accounting Policies (Revenue Recognition) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk
Revenues	$ 153,205	$ 154,641	$ 199,448	$ 173,291	$ 206,266	$ 213,922	$ 175,008	$ 130,958	$ 680,585	$ 726,154	$ 390,869
Refined products terminals and storage
Concentration Risk
Revenues									$ 23,227	23,287	24,011
Refined products terminals and storage | Minimum
Revenue Recognition
Initial term before evergreen provisions									6 months
Refined products terminals and storage | Maximum
Revenue Recognition
Initial term before evergreen provisions									2 years
Operating segment | Crude oil supply and logistics | Customer A | Sales Revenue | Customer Concentration Risk
Concentration Risk
Revenues									$ 252,969	164,115
Operating segment | Crude oil supply and logistics | Customer B | Sales Revenue | Customer Concentration Risk
Concentration Risk
Revenues										$ 90,923	$ 48,544

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Discontinued Operations (Details) - USD ($)		12 Months Ended		24 Months Ended
	Feb. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Discontinued operations
Loss on sale			$ 7,288,000
Goodwill allocated to discontinued operations		$ 216,692,000	240,782,000	$ 240,782,000	$ 242,766,000
Goodwill allocated to discontinued operations			$ 1,984,000
Impairment loss		29,896,000		$ 0
Mid-Continent Business | Held-for-sale
Discontinued operations
Goodwill allocated to discontinued operations		7,939,000
Impairment loss		$ 7,939,000
Mid-Continent Business | Disposed of by Sale
Discontinued operations
Sales Price	$ 9,685,000
Forecast | Mid-Continent Business | Disposed of by Sale
Discontinued operations
Loss on sale	$ 12,909,000

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Discontinued Operations (Income Statement) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OTHER INCOME (EXPENSE)
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$ (13,839)	$ (1,247)	$ 542	$ (407)	$ (491)	$ 800	$ (9,471)	$ (113)	$ (14,951)	$ (9,275)	$ 13,975
Mid-Continent Business | Held-for-sale
REVENUES
Crude oil sales									429,716	967,359	1,711,036
Gathering, transportation and storage fees									16	31	204
Other revenues									52	90	124
Total revenues									429,784	967,480	1,711,364
COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization									426,886	961,428	1,687,827
Operating expense									1,402	1,930	4,197
General and administrative									867	936	996
Impairment of goodwill and assets held for sale									12,909
Depreciation and amortization									2,281	2,258	2,358
Loss on disposal of assets, net									119	229
Total costs and expenses									444,464	966,781	1,695,378
OPERATING INCOME (LOSS)									(14,680)	699	15,986
OTHER INCOME (EXPENSE)
Interest expense									(296)	(412)	(830)
Other income, net									25	46	1
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES									(14,951)	333	15,157
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX									$ (14,951)	$ 333	$ 15,157

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Discontinued Operations (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Total Current assets of discontinued operations held for sale	$ 2,730	$ 15,149
Non-current assets
Total Non-current assets of discontinued operations held for sale	6,644	21,721
Current liabilities
Total Current liabilities of discontinued operations held for sale	640
Mid-Continent Business | Held-for-sale
Current assets
Inventory	2,692	15,149
Prepaid expenses and other current assets	38
Total Current assets of discontinued operations held for sale	2,730	15,149
Non-current assets
Property, plant and equipment, net	5,203	10,458
Goodwill		7,939
Intangible assets, net	1,138	2,981
Deferred financing costs and other assets, net	303	343
Total Non-current assets of discontinued operations held for sale	6,644	21,721
Total Assets of discontinued operations held for sale	9,374	$ 36,870
Current liabilities
Accrued liabilities	640
Total Current liabilities of discontinued operations held for sale	$ 640

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Discontinued Operations (Additional Disclosures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investing noncash items related to discontinued operations
Accrued capital expenditures	$ 12,475	$ 52,000
Capital Expenditures Incurred but Not yet Paid	3,796	3,628	$ 977
Mid-Continent Business | Held-for-sale
Discontinued operations
Depreciation	1,127	1,104	1,204
Amortization	1,154	1,154	1,154
Capital expenditures	637	316	$ 1,327
Other operating noncash items related to discontinued operations:
Impairment of goodwill and assets held for sale	12,909
Derivative valuation changes	630
Loss on disposal of assets	$ 119	229
Non-cash inventory LCM adjustments		222
Investing noncash items related to discontinued operations
Capital Expenditures Incurred but Not yet Paid		$ 218

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Discontinued Operations (Bakken) (Details) - USD ($)	3 Months Ended	12 Months Ended			24 Months Ended
	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Discontinued operations
Loss on sale			$ 7,288,000
Goodwill allocated to discontinued operations		$ 216,692,000	240,782,000	$ 242,766,000	$ 240,782,000
Goodwill written off			1,984,000
Impairment loss		$ 29,896,000			$ 0
Bakken Business | Disposed of by Sale
Discontinued operations
Sales Price	$ 9,100,000
Loss on sale	7,288,000		7,288,000
Goodwill allocated to discontinued operations	$ 1,984,000
Goodwill written off			1,984,000
Revenues from discontinued operations			7,865,000
Net (loss) gain of discontinued operations, net of taxes, including loss on disposal of $7,288 in 2014			$ (9,608,000)
Bakken Business | Held-for-sale
Discontinued operations
Revenues from discontinued operations				19,283,000
Net (loss) gain of discontinued operations, net of taxes, including loss on disposal of $7,288 in 2014				$ (1,182,000)

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Net Loss Per Unit (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended					12 Months Ended
	Jan. 26, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Net loss per unit
Distribution declared (in dollars per unit)	$ 0.325
Net loss from continuing operations attributable to the limited partners:
Distribution declared							$ 47,743	$ 11,014
Distribution in excess of net income							(91,448)	(29,964)
Net loss from continuing operations allocated to limited partners							(43,705)	(18,950)
Net loss from discontinued operations attributable to the limited partners							(14,951)	334
Net loss attributable to limited partners							$ (58,656)	$ (18,616)
Weighted average units outstanding:
Basic (in shares)							36,525,294	36,422,580
Net income (loss) per unit:
Basic and diluted net loss from continuing operations (in dollars per unit)						$ (0.52)
Basic and diluted total (in dollars per unit)						$ (0.51)
Common
Net loss from continuing operations attributable to the limited partners:
Distribution declared							$ 24,172	$ 5,523
Distribution in excess of net income							(46,002)	(14,983)
Net loss from continuing operations allocated to limited partners							(21,830)	(9,460)
Net loss from discontinued operations attributable to the limited partners							(7,521)	167
Net loss attributable to limited partners							$ (29,351)	$ (9,293)
Weighted average units outstanding:
Basic (in shares)							18,373,594	18,212,632
Net income (loss) per unit:
Basic and diluted net loss from continuing operations (in dollars per unit)		$ (0.88)	$ (0.19)	$ (0.15)	$ 0.03		$ (1.19)	$ (0.52)
Basic and diluted from discontinued operations (in dollars per share)							(0.41)	0.01
Basic and diluted total (in dollars per unit)		(1.26)	(0.23)	(0.13)	0.02		$ (1.60)	$ (0.51)
Subordinated
Net loss from continuing operations attributable to the limited partners:
Distribution declared							$ 23,571	$ 5,491
Distribution in excess of net income							(45,446)	(14,981)
Net loss from continuing operations allocated to limited partners							(21,875)	(9,490)
Net loss from discontinued operations attributable to the limited partners							(7,430)	167
Net loss attributable to limited partners							$ (29,305)	$ (9,323)
Weighted average units outstanding:
Basic (in shares)							18,151,700	18,209,948
Net income (loss) per unit:
Basic and diluted net loss from continuing operations (in dollars per unit)		(0.88)	(0.20)	(0.15)	0.03		$ (1.20)	$ (0.52)
Basic and diluted from discontinued operations (in dollars per share)							(0.41)	0.01
Basic and diluted total (in dollars per unit)		$ (1.26)	$ (0.23)	$ (0.14)	$ 0.02		$ (1.61)	$ (0.51)

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Net Loss Per Unit (Antidilutive) (Details)	12 Months Ended
	Dec. 31, 2015 shares
Antidilutive securities excluded from computation of diluted earnings per unit
Phantom units	406,218

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Acquisitions and Dispositions (2015 Acquisitions) (Details) - USD ($)		8 Months Ended	12 Months Ended
	May. 08, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allocation of total purchase price to assets acquired and liabilities assumed
Goodwill		$ 216,692,000	$ 216,692,000	$ 240,782,000	$ 242,766,000
Southern Propane Member
Acquisitions
Total purchase price	$ 16,292,000
Consideration - cash payment	12,475,000
Consideration - working capital adjustment	$ 108,000
Equity issued as part of acquisition (in units)	266,951
Value of equity issued as part of acquisition	$ 3,442,000
Contingent earn-out at fair value	267,000
Maximum contingent earn-out	1,250,000
Decrease in Fair Value of Contingent Consideration Liability		243,000	243,000
Realized gains due to the changes in fair value of liabilities			24,000
Allocation of total purchase price to assets acquired and liabilities assumed
Accounts receivable	932,000
Inventory	24,000
Total current assets	956,000
Property, plant and equipment	2,962,000
Total identifiable net assets acquired	10,486,000
Goodwill	5,806,000
Net assets acquired	16,292,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		3,849,000
Acquisition - pro forma information
Revenues attributable to acquiree since acquisition date		3,849,000
Southern Propane Member | Customer relationships
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets	$ 6,163,000
Intangible assets
Weighted average useful life	12 years
Southern Propane Member | Noncompete agreements
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets	$ 292,000
Intangible assets
Weighted average useful life	5 years
Southern Propane Member | Trade names
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets	$ 113,000
Intangible assets
Weighted average useful life	1 year
NGL distribution and sales
Allocation of total purchase price to assets acquired and liabilities assumed
Goodwill		$ 30,819,000	$ 30,819,000	$ 31,335,000	$ 31,335,000

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Acquisitions and Dispositions (2013 Acquisitions) (Details) - USD ($)		3 Months Ended	12 Months Ended
	Oct. 07, 2013	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Allocation of total purchase price to assets acquired and liabilities assumed
Goodwill		$ 242,766,000	$ 216,692,000	$ 240,782,000
Wildcat Permian Service LLC | Crude oil supply and logistics
Allocation of total purchase price to assets acquired and liabilities assumed
Goodwill	$ 11,242,000
JP Development | Wildcat Permian Service LLC
Acquisitions
Consideration - cash payment	212,804,000
Allocation of total purchase price to assets acquired and liabilities assumed
Cash	2,570,000
Accounts receivable	16,068,000
Inventory	283,000
Short-term prepaid asset	134,000
Total current assets	19,055,000
Property, plant and equipment	33,962,000
Long-term prepaid asset	951,000
Total assets acquired	121,668,000
Total liabilities assumed	(17,227,000)
Total identifiable net assets acquired	104,441,000
Goodwill	108,363,000
Net assets acquired	212,804,000
Acquisition - pro forma information
Revenues attributable to acquiree since acquisition date		$ 10,878,000	$ 70,580,000	$ 64,136,000
JP Development | Wildcat Permian Service LLC | Customer relationships
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets	$ 67,700,000
Intangible assets
Weighted average useful life	17 years

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Acquisitions and Dispositions (Other 2013 Acquisitions) (Details)				3 Months Ended	12 Months Ended
	Oct. 11, 2013 USD ($)	Aug. 30, 2013 USD ($)	Jul. 15, 2013 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($) item
Allocation of total purchase price to assets acquired and liabilities assumed
Goodwill					$ 216,692,000	$ 240,782,000	$ 242,766,000
JP Development | Partnership Interests | Class C Common Unit
Acquisitions
Value of equity issued as part of acquisition							1,628,000
JP Development | Other 2013 Acquisitions
Acquisitions
Total purchase price							27,048,000
Consideration - cash payment							$ 23,085,000
Realized gains due to the changes in fair value of liabilities					1,435,000
Realized losses due to changes in fair value of liabilities						435,000
Number of acquisitions | item							3
Allocation of total purchase price to assets acquired and liabilities assumed
Accounts receivable							$ 504,000
Inventory							15,000
Total current assets							519,000
Property, plant and equipment							8,503,000
Total assets acquired							17,759,000
Total liabilities assumed							(475,000)
Total identifiable net assets acquired							17,284,000
Goodwill							9,764,000
Net assets acquired							27,048,000
Acquisition - pro forma information
Revenues attributable to acquiree since acquisition date					$ 14,008,000	18,329,000	5,781,000
JP Development | Other 2013 Acquisitions | Trade names and trademarks
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets							$ 286,000
Intangible assets
Estimated useful life							2 years
JP Development | Other 2013 Acquisitions | Customer relationships
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets							$ 8,022,000
Intangible assets
Weighted average useful life							6 years
JP Development | Other 2013 Acquisitions | Noncompete agreements
Allocation of total purchase price to assets acquired and liabilities assumed
Intangible assets							$ 429,000
Intangible assets
Estimated useful life							3 years
JP Development | BMH Propane, LLC (d/b/a Valley Gas)
Acquisitions
Total purchase price			$ 2,437,000
JP Development | Alexander Oil Field Service, Inc.
Acquisitions
Total purchase price		$ 7,792,000
Contingent earn-out at fair value		$ 1,280,000				790,000
Maximum contingent earn-out							$ 1,628,000
Term of earn-out of contingent liability					2 years
Settlement of Contingent Liability				$ 488,000
JP Development | Highway Pipeline, Inc.
Acquisitions
Total purchase price	$ 16,819,000
Contingent earn-out at fair value	$ 1,055,000				$ 234,000	$ 1,367,000
Maximum contingent earn-out							$ 3,000,000
Term of earn-out of contingent liability					3 years

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Acquisitions and Dispositions (Pro Forma) (Details) - JP Development $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($)
Pro forma consolidated revenue	$ 393,837
Pro forma consolidated net loss	$ (32,501)

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Acquisitions and Dispositions (Disposition) (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations	Nov. 02, 2015 USD ($)
Discontinued operations
Disposal Group, Excluding Discontinued Operation, Consideration	$ 1,914,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 1,046,000

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Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Inventory
Total inventory	$ 4,786	$ 5,677
Crude oil
Inventory
Total inventory	338	162
NGLs
Inventory
Total inventory	2,364	3,342
Diesel
Inventory
Total inventory	430	445
Materials, supplies and equipment
Inventory
Total inventory	$ 1,654	$ 1,728

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Property, Plant and Equipment, net (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment, net
Total property, plant and equipment	$ 365,935,000	$ 301,399,000
Less: accumulated depreciation	(74,481,000)	(49,709,000)
Property, Plant and Equipment, Net, Total	291,454,000	251,690,000
Depreciation expenses	29,391,000	23,514,000	$ 18,779,000
Land
Property, Plant and Equipment, net
Total property, plant and equipment	6,874,000	6,874,000
Building and Building Improvements
Property, Plant and Equipment, net
Total property, plant and equipment	12,561,000	12,045,000
Transportation equipment
Property, Plant and Equipment, net
Total property, plant and equipment	46,582,000	39,388,000
Storage And Propane Tanks
Property, Plant and Equipment, net
Total property, plant and equipment	151,988,000	139,721,000
Pipelines and linefill
Property, Plant and Equipment, net
Total property, plant and equipment	77,295,000	54,059,000
Office furniture and fixtures
Property, Plant and Equipment, net
Total property, plant and equipment	9,701,000	8,245,000
Other equipment
Property, Plant and Equipment, net
Total property, plant and equipment	48,171,000	25,892,000
Construction in Progress
Property, Plant and Equipment, net
Total property, plant and equipment	12,763,000	15,175,000
Discontinued Operations, Held-for-sale or Disposed of by Sale | Mid-Continent and Bakken Business
Property, Plant and Equipment, net
Depreciation expenses	$ 1,127,000	$ 1,685,000	$ 2,348,000

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Goodwill and Intangible Assets (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Intangible assets
Gross carrying amount	$ 182,550,000	$ 178,144,000
Accumulated amortization	(48,118,000)	(32,814,000)
Net carrying amount	134,432,000	145,330,000
Amortization expense	17,461,000	16,716,000	$ 12,208,000
Customer relationships
Intangible assets
Gross carrying amount	82,630,000	76,466,000
Accumulated amortization	(20,761,000)	(14,275,000)
Net carrying amount	61,869,000	62,191,000
Noncompete agreements
Intangible assets
Gross carrying amount	3,575,000	3,728,000
Accumulated amortization	(2,664,000)	(2,283,000)
Net carrying amount	911,000	1,445,000
Trade names
Intangible assets
Gross carrying amount	553,000	2,147,000
Accumulated amortization	(139,000)	(583,000)
Net carrying amount	414,000	1,564,000
Customer contract
Intangible assets
Gross carrying amount	95,594,000	95,594,000
Accumulated amortization	(24,538,000)	(15,662,000)
Net carrying amount	71,056,000	79,932,000
Other
Intangible assets
Gross carrying amount	198,000	209,000
Accumulated amortization	(16,000)	(11,000)
Net carrying amount	182,000	198,000
Discontinued Operations, Held-for-sale or Disposed of by Sale | Mid-Continent and Bakken Business
Intangible assets
Amortization expense	1,154,000	2,007,000	$ 2,860,000
Disposed of by Sale | Customer contract | Bakken Business
Intangible assets
Intangible assets, written off		$ 8,060,000
Held-for-sale | Customer relationships | Mid-Continent Business
Intangible assets
Intangible assets, written off	$ 689,000

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Goodwill and Intangible Assets (Amortization) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Estimated future amortization expense for amortizable intangible assets
2016	$ 16,163
2017	15,754
2018	15,484
2019	13,499
2020	10,790
Thereafter	62,742
Net carrying amount	$ 134,432	$ 145,330

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Goodwill and Intangible Assets (Goodwill) (Details) - USD ($)	12 Months Ended		24 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014
Goodwill activity
Balance at beginning	$ 240,782,000	$ 242,766,000
Goodwill acquired during the year	5,806,000
Goodwill impairment	(29,896,000)		$ 0
Disposals		(1,984,000)
Balance at end	216,692,000	240,782,000	240,782,000
Crude oil pipelines and storage
Goodwill activity
Balance at beginning	148,284,000	150,268,000
Goodwill impairment	(23,574,000)
Disposals		(1,984,000)
Balance at end	124,710,000	148,284,000	148,284,000
Refined products terminals and storage
Goodwill activity
Balance at beginning	61,163,000	61,163,000
Balance at end	61,163,000	61,163,000	61,163,000
NGL distribution and sales
Goodwill activity
Balance at beginning	31,335,000	31,335,000
Goodwill acquired during the year	5,806,000
Goodwill impairment	(6,322,000)
Balance at end	30,819,000	31,335,000	$ 31,335,000
Crude Oil Supply and Logistics and JP Liquids
Goodwill activity
Goodwill impairment	(29,896,000)
Crude Oil Supply and Logistics | Crude oil pipelines and storage
Goodwill activity
Goodwill impairment	(23,574,000)
Held-for-sale | Mid-Continent Business
Goodwill activity
Goodwill impairment	(7,939,000)
Balance at end	$ 7,939,000
Disposed of by Sale | Bakken Business
Goodwill activity
Disposals		(1,984,000)
Decrease in goodwill		$ 1,984,000

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Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities
Taxes payable	$ 1,204	$ 1,915
Accrued payroll and employee benefits	4,756	8,148
Accrued professional fees	696	462
Royalties payable	4,163	4,281
Short-term derivative liabilities	358	10,157
Other	4,083	4,008
Total accrued liabilities	$ 15,260	$ 28,971

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Capital Leases and Other Short-Term Debt (Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets under capital lease agreements
Capital Leased Assets, Gross	$ 351	$ 577
Less: Accumulated depreciation	(197)	(254)
Assets under capital lease, net	154	323
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity
2016	153
2017	116
2018	40
2019	31
2020	22
Thereafter	11
Capital Leases, Future Minimum Payments Due, Total	373
Less: amounts representing interest	(137)
Total obligations under capital leases	236
Less: current portion	(107)
Long-term capital lease obligation	129
Building and Building Improvements
Assets under capital lease agreements
Capital Leased Assets, Gross	16	138
Transportation equipment
Assets under capital lease agreements
Capital Leased Assets, Gross	167	261
Office Furniture and Equipment
Assets under capital lease agreements
Capital Leased Assets, Gross	133	129
Other equipment
Assets under capital lease agreements
Capital Leased Assets, Gross	$ 35	$ 49

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Capital Leases and Other Short-Term Debt (Other Debt) (Details)	Dec. 31, 2014 USD ($)
Bank Overdrafts
Other Short-Term Debt
Bank overdrafts outstanding	$ 91,000
Secured by Insurance Premium
Other Short-Term Debt
Outstanding short term debt	$ 49,000

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Long-Term Debt (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Feb. 12, 2014
Long-Term Debt
Total long-term debt	$ 163,194,000	$ 84,508,000
Less: Current maturities	(454,000)	(383,000)
Long-term Debt, Excluding Current Maturities	162,740,000	84,125,000
Revolving loans | Bank of America, N.A
Long-Term Debt
Total long-term debt	162,000,000	83,000,000
Loans | F&M bank
Long-Term Debt
Total long-term debt			$ 4,135,000
Notes payable | HBH
Long-Term Debt
Total long-term debt	1,077,000	1,277,000
Noncompete notes payable
Long-Term Debt
Total long-term debt	$ 117,000	$ 231,000

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Long-Term Debt (BOA) (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 12, 2014 USD ($)
Long-Term Debt
Total long-term debt	$ 163,194,000	$ 84,508,000
Credit Agreement | Bank of America, N.A
Long-Term Debt
Unused balance	86,870,000
Available borrowings	$ 26,130,000
Commitment fee on the unused commitments (as a percent)	0.50%
Credit Agreement | Bank of America, N.A | Prior to the closing of the IPO
Long-Term Debt
Consolidated total leverage ratio prior to the issuance of certain unsecured notes for certain measurement periods following consummation of certain acquisitions	4.75
Credit Agreement | Bank of America, N.A | Minimum
Long-Term Debt
Consolidated Working Capital Covenant	$ 15,000,000
Credit Agreement | Bank of America, N.A | Minimum | Prior to the closing of the IPO
Long-Term Debt
Consolidated Working Capital Covenant	$ 15,000,000
Consolidated interest coverage ratio	2.50
Credit Agreement | Bank of America, N.A | Minimum | After the closing of the IPO
Long-Term Debt
Available Liquidity Covenant	$ 25,000,000
Consolidated interest coverage ratio	2.50
Credit Agreement | Bank of America, N.A | Maximum | Prior to the closing of the IPO
Long-Term Debt
Consolidated total leverage ratio prior to the issuance of certain unsecured notes	4.50
Consolidated total leverage ratio after the issuance of certain unsecured notes	4.75
Consolidated senior secured leverage ratio after the issuance of certain unsecured notes	3.00
Credit Agreement | Bank of America, N.A | Maximum | After the closing of the IPO
Long-Term Debt
Consolidated total leverage ratio prior to the issuance of certain unsecured notes	4.50
Consolidated total leverage ratio after the issuance of certain unsecured notes	5.00
Consolidated senior secured leverage ratio after the issuance of certain unsecured notes	3.50
Credit Agreement | Bank of America, N.A | Federal funds effective rate
Long-Term Debt
Interest rate spread (as a percent)	0.50%
Credit Agreement | Bank of America, N.A | LIBOR
Long-Term Debt
Interest rate spread (as a percent)	1.00%
Initial applicable margin (as a percent)	2.25%
Credit Agreement | Bank of America, N.A | Prime rate
Long-Term Debt
Initial applicable margin (as a percent)	1.25%
Revolving loans | Bank of America, N.A
Long-Term Debt
Total long-term debt	$ 162,000,000	83,000,000
Revolving loans | Credit Agreement | Bank of America, N.A
Long-Term Debt
Maximum borrowing capacity	275,000,000		$ 275,000,000
Amount that maximum borrowing capacity can increase to	425,000,000
Letters of credit | Credit Agreement | Bank of America, N.A | Maximum
Long-Term Debt
Maximum borrowing capacity			$ 100,000,000
Noncompete notes payable
Long-Term Debt
Total long-term debt	$ 117,000	$ 231,000

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Long-Term Debt (HBH and Non-Compete) (Details) - USD ($)	12 Months Ended			36 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Nov. 15, 2011
Long-Term Debt
Outstanding balance	$ 163,194,000	$ 84,508,000		$ 163,194,000
Notes payable | HBH
Long-Term Debt
Face amount					$ 2,012,500
Outstanding balance	$ 1,077,000	1,277,000		$ 1,077,000
Interest rate (as a percent)	5.00%			5.00%
Accretion expense	$ 55,000	66,000	$ 69,000
Notes payable | HBH | Minimum
Long-Term Debt
Periodic payment amount	2,012,500
Noncompete notes payable
Long-Term Debt
Outstanding balance	117,000	231,000		$ 117,000
Noncompete notes payable | HPX
Long-Term Debt
Term of debt instrument				5 years
Fair value of debt	$ 117,000	$ 231,000		$ 117,000
Effective borrowing rate (as a percent)	3.50%			3.50%

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Long-Term Debt (Wells Fargo Agreement) (Details)	12 Months Ended
	Dec. 31, 2014 USD ($)
Long-Term Debt
Deferred financing costs written off	$ 1,634,000
Credit Agreement | Wells Fargo Bank, N.A.
Long-Term Debt
Deferred financing costs written off	1,634,000
Working capital revolving credit facility | Wells Fargo Bank, N.A.
Long-Term Debt
Maximum borrowing capacity	20,000,000
Acquisition revolving credit facility | Wells Fargo Bank, N.A.
Long-Term Debt
Maximum borrowing capacity	$ 180,000,000

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Long-Term Debt (F&M, Reynolds and Related Party) (Details)	May. 01, 2014 USD ($)	May. 01, 2013 USD ($)	May. 01, 2012 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 12, 2014 USD ($)	Nov. 05, 2013 USD ($)
Long-Term Debt
Outstanding balance				$ 163,194,000	$ 84,508,000
JP Development
Long-Term Debt
Face amount							$ 1,000,000
Interest rate (as a percent)							4.75%
Loans | F&M bank
Long-Term Debt
Outstanding balance						$ 4,135,000
Notes payable | JP Development
Long-Term Debt
Face amount							$ 1,000,000
Interest rate (as a percent)							4.75%
Notes payable | Reynolds
Long-Term Debt
Face amount			$ 645,000
Number of installment payments | item			2
Periodic payment amount	$ 350,000	$ 295,000

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Long-Term Debt (Repayment schedule) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Scheduled principal repayments of long-term debt
2016	$ 454
2017	740
2019	162,000
Outstanding balance	$ 163,194	$ 84,508

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Derivative Instruments (Details)	1 Months Ended	12 Months Ended
	Aug. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) item gal	Dec. 31, 2014 USD ($) gal
Derivative Instruments
Early Settlement of Commodity Derivatives	$ 8,745,000	$ 8,745,000
Derivative Assets
Derivative contracts - current, Gross Amount Recognized		92,000
Derivative contracts - current, Gross Amounts Offset		(92,000)
Derivative Liabilities
Derivative contracts - current, Gross Amount Recognized		450,000
Derivative contracts - current, Gross Amounts Offset		(92,000)
Derivative contracts - current , Net Amounts Presented in the Balance Sheet		358,000	$ 10,157,000
Derivative contracts - current, Net Amount		358,000
Derivative contracts - noncurrent, Gross Amount Recognized		24,000
Derivative contracts - noncurrent , Net Amounts Presented in the Balance Sheet		24,000
Derivative contracts - noncurrent, Net Amount		$ 24,000
Forward Contracts | Fixed Price Swap
Derivative Instruments
Notional amount (in gallons or barrels) | gal		8,614,631	27,958,302
Commodity swap contracts | Fixed Price Swap
Derivative Instruments
Notional amount		$ 93,000
Interest rate swap contracts
Derivative Instruments
Notional amount			$ 75,000,000
Derivatives designated as hedging contracts
Derivative Instruments
Number of derivative contracts | item		0
Derivatives not designated as hedging contracts | Commodity swap contracts | Prepaid expenses and other current assets
Derivative Instruments
Asset Derivatives		$ 92,000
Derivatives not designated as hedging contracts | Commodity swap contracts | Accrued liabilities.
Derivative Instruments
Liability Derivatives		(450,000)	(8,941,000)
Derivatives not designated as hedging contracts | Commodity swap contracts | Other long-term liabilities
Derivative Instruments
Liability Derivatives		(24,000)	(3,251,000)
Derivatives not designated as hedging contracts | Interest rate swap contracts | Accrued liabilities.
Derivative Instruments
Liability Derivatives			$ (158,000)
Held-for-sale | Mid-Continent Business | Forward Contracts | Current liabilities of discontinued operations held for sale
Derivative Instruments
Liability Derivatives		$ (630,000)

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Derivative Instruments (GainLoss) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity swap contracts | Cost of sales
Derivative Instruments
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (3,056,000)	$ (13,762,000)	$ 902,000
Interest rate swap contracts | Interest expense
Derivative Instruments
Amount of Gain/(Loss) Recognized in Income on Derivatives	(27,000)	$ (227,000)	$ (168,000)
Held-for-sale | Mid-Continent Business
Derivative Instruments
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (1,962,000)

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Partners' Capital (Details)							12 Months Ended
	May. 08, 2015 USD ($) shares	Oct. 07, 2014 USD ($) shares	Oct. 07, 2014 USD ($) shares	Mar. 28, 2014 USD ($) $ / shares shares	Feb. 12, 2014 USD ($) shares	Aug. 01, 2013 shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($) shares
Partners' Capital
Total proceeds from sale of units | $			$ 257,100,000
Proceeds from issuance of preferred units | $							$ 40,000,000
Amount of redemption of preferred units | $							42,436,000
Proceeds from issuance of common units | $							$ 262,638,000	$ 3,128,000
Southern Propane Member
Partners' Capital
Equity issued as part of acquisition (in units)	266,951
Value of equity issued as part of acquisition | $	$ 3,442,000
Series D Preferred Unit
Partners' Capital
Units issued as in-kind distributions (in units)							110,727
Amount of redemption of preferred units | $		$ 42,436,000
Lonestar | Series A, Series B and Series C Preferred units
Partners' Capital
Preferred units conversion ratio						1
Lonestar | Series D Preferred Unit
Partners' Capital
Units issued in private placements (in units)				1,818,182
Issuance price (in dollars per unit) | $ / shares				$ 22.00
Proceeds from issuance of preferred units | $				$ 40,000,000
Lonestar | Series C Preferred Unit
Partners' Capital
Conversion of units (in units)						(59,270)
Lonestar | Series B Preferred Unit
Partners' Capital
Conversion of units (in units)						(552,348)
Lonestar | Series A Preferred Unit
Partners' Capital
Conversion of units (in units)						(524,746)
Common | IPO
Partners' Capital
Number of common units issued to the public		13,750,000	13,750,000
Percentage of ownership interest in partnership		37.70%	37.70%
Total proceeds from sale of units | $		$ 257,100,000
Class A Common Unit | Lonestar
Partners' Capital
Units issued in private placements (in units)					363,636
Proceeds from issuance of common units | $					$ 8,000,000
Class C Common Unit | JP Development
Partners' Capital
Units issued in private placements (in units)								88,114
Proceeds from issuance of common units | $								$ 3,128,000
Class C Common Unit | JP Development | Partnership Interests
Partners' Capital
Value of equity issued as part of acquisition | $								$ 1,628,000
Existing Common Units | Prior to the closing of the IPO
Partners' Capital
Percentage of ownership interest in partnership			19.70%				80.30%
Conversion of units (in units)			(18,213,502)
Unit split ratio			0.89				0.89
Number of common units resulting from unit split			22,677,004
Existing Common Units | After the closing of the IPO
Partners' Capital
Conversion of units (in units)			(4,463,502)
Common units conversion ratio			1
Subordinated | Prior to the closing of the IPO
Partners' Capital
Percentage of ownership interest in partnership			80.30%				19.70%
Conversion of units (in units)			18,213,502
Subordinated | After the closing of the IPO
Partners' Capital
Percentage of ownership interest in partnership			50.00%

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Partners' Capital (Subordinated) (Details) - $ / shares				1 Months Ended							12 Months Ended
	Feb. 12, 2016	Feb. 13, 2015	Oct. 07, 2014	Nov. 30, 2015	Aug. 31, 2015	May. 31, 2015	Feb. 28, 2015	Aug. 31, 2013	Jul. 31, 2013	Feb. 28, 2013	Dec. 31, 2015	Dec. 31, 2013
Partners' Capital
General partner, units outstanding												45
Number of general partner units recharacterized as non-economic general partner interest			45
Incentive distribution rights, first tier (as a percent)											15.00%
Incentive distribution rights, second tier (as a percent)											25.00%
Incentive distribution rights, third tier (as a percent)											50.00%
First target distribution (in dollars per unit)											$ 0.37375
Second target distribution (in dollars per unit)											0.40625
Third target distribution (in dollars per unit)											$ 0.4875
Cash Distribution (in dollars per unit)	$ 0.325			$ 0.3250	$ 0.3250	$ 0.3250		$ 0.5000	$ 0.5000	$ 0.5000
Distributions to unitholders
Partners' Capital
Distribution of available cash, after minimum and arrearages (as a percent)											100.00%
Distribution of available cash, second target distribution (as a percent)											85.00%
Distribution of available cash, third target distribution (as a percent)											75.00%
Distribution of available cash, after third target distribution (as a percent)											50.00%
Cash Distribution (in dollars per unit)							$ 0.3038
Distributions to unitholders | Prior to the closing of the IPO
Partners' Capital
Period for distribution of available cash											60 days
Distributions to unitholders | After the closing of the IPO
Partners' Capital
Period for distribution of available cash											45 days
Minimum quarterly distribution
Partners' Capital
Cash Distribution (in dollars per unit)		$ 0.3250
Incentive distributions
Partners' Capital
Distribution of available cash, second target distribution (as a percent)											15.00%
Distribution of available cash, third target distribution (as a percent)											25.00%
Distribution of available cash, after third target distribution (as a percent)											50.00%
Subordinated
Partners' Capital
Conversion ratio of subordinated units to common units											1
Distributions for any quarter during the subordination period | Subordinated | Minimum quarterly distribution
Partners' Capital
Distributions of available cash (in dollars per unit)											$ 0.3250

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Partners' Capital (Valuation) (Details)	Dec. 31, 2014	Apr. 19, 2013
Minimum
Partners' Capital
WACC (as a percent)	10.71%	9.41%
Market multiple (as a percent)	12.05	10.50
Maximum
Partners' Capital
WACC (as a percent)	11.21%	9.91%
Market multiple (as a percent)	12.55	11.00

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Unit-Based Compensation (Details)		3 Months Ended	12 Months Ended
	Oct. 07, 2014	Jun. 30, 2015 USD ($) shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) $ / shares shares	Dec. 31, 2013 USD ($) $ / shares shares
Unit-Based Compensation
Limited Partners' Capital Account, Units Authorized			22,119,170	21,852,219
2015 Phantom Units Member
Unit-Based Compensation
Limited Partners' Capital Account, Units Authorized				3,642,700
Units
Outstanding at the end of the period (in units)			392,420
Weighted Average Grant Date Fair Value
Outstanding at the end of the period (in dollars per unit) | $ / shares			$ 12.99
Additional information
Equity based compensation expense (in dollars) | $			$ 849,000
Compensation expense expected to be recognized (in dollars) | $			$ 2,500,000
Weighted average period for expected recognition of compensation expense			1 year 7 months 6 days
Estimated forfeiture rate (as a percent)			41.00%
Service condition
Unit-Based Compensation
Vesting period				3 years
Service condition | 2015 Phantom Units Member
Units
Granted (in units)			497,479
Vested (in units)			(8,250)
Forfeited (in units)			(96,809)
Weighted Average Grant Date Fair Value
Granted (in dollars per unit) | $ / shares			$ 12.84
Vested (in dollars per unit) | $ / shares			12.90
Forfeited (in dollars per unit) | $ / shares			$ 12.26
Class B Common Unit | Performance condition
Units
Granted (in units)					75,000
Forfeited (in units)		(25,000)
Common Stock Unissued | $			$ 25,000
Unit Based Compensation Expense Reversal | $		$ 297,000
Class B Common Unit | Performance condition | Maximum
Unit-Based Compensation
Limited Partners' Capital Account, Units Authorized			100,000
Prior to the closing of the IPO | Existing Common Units
Additional information
Unit split ratio	0.89			0.89
Percentage of ownership interest in partnership	19.70%			80.30%
Prior to the closing of the IPO | Subordinated
Additional information
Percentage of ownership interest in partnership	80.30%			19.70%
Restricted Common Units of JPE | Common
Units
Outstanding at the beginning of the period (in units)			31,012
Outstanding at the end of the period (in units)			6,424	31,012
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per unit) | $ / shares			$ 24.36
Outstanding at the end of the period (in dollars per unit) | $ / shares			$ 25.91	$ 24.36
Restricted Common Units of JPE | Subordinated
Units
Outstanding at the beginning of the period (in units)			126,553
Outstanding at the end of the period (in units)			26,216	126,553
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per unit) | $ / shares			$ 24.36
Outstanding at the end of the period (in dollars per unit) | $ / shares			$ 25.91	$ 24.36
Restricted Common Units of JPE | Service condition | Common
Units
Vested (in units)			(10,512)	(876)
Forfeited (in units)			(14,076)	(2,715)
Weighted Average Grant Date Fair Value
Vested (in dollars per unit) | $ / shares			$ 25.37	$ 36.75
Forfeited (in dollars per unit) | $ / shares			$ 22.89	$ 39.22
Restricted Common Units of JPE | Service condition | Subordinated
Units
Vested (in units)			(42,898)
Forfeited (in units)			(57,439)
Weighted Average Grant Date Fair Value
Vested (in dollars per unit) | $ / shares			$ 25.37
Forfeited (in dollars per unit) | $ / shares			$ 22.89
Restricted Common Units of JPE | Class B Common Unit
Units
Outstanding at the beginning of the period (in units)				177,867	143,000
Outstanding at the end of the period (in units)					177,867
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per unit) | $ / shares				$ 25.58	$ 20.32
Outstanding at the end of the period (in dollars per unit) | $ / shares					$ 25.58
Additional information
Equity based compensation expense (in dollars) | $			$ 460,000	$ 1,789,000	$ 948,000
Compensation expense expected to be recognized (in dollars) | $			$ 561,000
Weighted average period for expected recognition of compensation expense			1 year 5 months 1 day
Ratio of distributions to per unit distributions paid to common units			1
Restricted Common Units of JPE | Class B Common Unit | Service condition
Units
Granted (in units)				90,000	68,500
Vested (in units)				(63,698)	(23,633)
Forfeited (in units)				(6,667)	(10,000)
Weighted Average Grant Date Fair Value
Granted (in dollars per unit) | $ / shares				$ 19.64	$ 34.91
Vested (in dollars per unit) | $ / shares				24.21	23.37
Forfeited (in dollars per unit) | $ / shares				$ 34.91	$ 19.51
Restricted Common Units of JPE | Class B Common Unit | Service condition | Minimum
Unit-Based Compensation
Vesting period			3 years
Restricted Common Units of JPE | Class B Common Unit | Service condition | Maximum
Unit-Based Compensation
Vesting period			5 years
Restricted Common Units of JPE | Subordinated | Subordinated
Units
Outstanding at the beginning of the period (in units)			126,553
Outstanding at the end of the period (in units)				126,553
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per unit) | $ / shares			$ 24.36
Outstanding at the end of the period (in dollars per unit) | $ / shares				$ 24.36
Restricted Common Units of JPE | Subordinated | Service condition | Subordinated
Units
Vested (in units)				(3,576)
Forfeited (in units)				(11,082)
Weighted Average Grant Date Fair Value
Vested (in dollars per unit) | $ / shares				$ 36.75
Forfeited (in dollars per unit) | $ / shares				$ 39.22
Restricted Common Units of JPE | IPO | Common
Units
Conversion upon IPO				34,603
Weighted Average Grant Date Fair Value
Conversion upon IPO | $ / shares				$ 25.84
Restricted Common Units of JPE | IPO | Class B Common Unit
Units
Conversion upon IPO				(197,502)
Weighted Average Grant Date Fair Value
Conversion upon IPO | $ / shares				$ 23.00
Restricted Common Units of JPE | IPO | Subordinated | Subordinated
Units
Conversion upon IPO				141,211
Weighted Average Grant Date Fair Value
Conversion upon IPO | $ / shares				$ 25.84

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Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) bbl	Dec. 31, 2013 USD ($)
Commitments and Contingencies
Operating expense recorded in statement of operations	$ 69,377,000	$ 65,584,000	$ 57,728,000
Operating leases
Rental expenses	5,741,000	4,806,000	$ 3,299,000
Operating Leases, Future Minimum Payments Due
2016	5,116,000
2017	4,331,000
2018	3,776,000
2019	2,383,000
2020	718,000
Thereafter	4,877,000
Total operating lease future payments	21,201,000
Refined products terminals and storage | North Little Rock, Arkansas
Commitments and Contingencies
Total Value of Products For Specified Contingency		$ 2,259,000
Estimated volume of products to be returned to customers | bbl		24,000
Volume of products returned to customers | bbl		20,900
Value of products returned to customers	172,000	$ 2,092,000
Remaining volume of products to be returned to customers | bbl		3,100
Remaining value of products to be returned to customers		$ 167,000
Parnon Storage, LLC
Operating leases
Land lease monthly payment	$ 10,000
Land lease remaining lease period	42 years

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Reportable Segments (Details)	12 Months Ended
	Dec. 31, 2015 item mi bbl
Reportable Segments
Number of reportable segment	3
Crude oil pipelines and storage | Permian Basin
Reportable Segments
Length of high-pressure steel pipeline | mi	148
Throughput capacity per day | bbl	130,000
Storage capacity | bbl	140,000
Crude oil pipelines and storage | Cushing, Oklahoma
Reportable Segments
Storage capacity | bbl	3,000,000
Refined products terminals and storage
Reportable Segments
Storage capacity | bbl	1,300,000
Number of refined product terminals	2
Refined products terminals and storage | North Little Rock, Arkansas
Reportable Segments
Storage capacity | bbl	550,000
Number of storage tanks	11
Number of loading lanes	8
Refined products terminals and storage | Caddo Mills, Texas
Reportable Segments
Storage capacity | bbl	770,000
Number of storage tanks	10
Number of loading lanes	5
NGL distribution and sales
Reportable Segments
Number of businesses	3
Number of states covered by cylinder exchange network	48
Number of locations covering cylinder exchange network	21,000
Number of states in which product is sold to retailers, wholesalers, industrial end-users and commercial and residential customers.	7

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Reportable Segments (Financial Data) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reportable Segments
Revenues	$ 153,205	$ 154,641	$ 199,448	$ 173,291	$ 206,266	$ 213,922	$ 175,008	$ 130,958	$ 680,585	$ 726,154	$ 390,869
Cost of sales, excluding depreciation and amortization									527,476	605,682	276,804
Operating expense									69,377	65,584	57,728
Depreciation and amortization									46,852	40,230	30,987
Adjusted EBITDA									64,882	51,573	41,097
Capital expenditures									71,011	56,878	26,828
Crude oil pipelines and storage
Reportable Segments
Revenues									480,527	495,971	186,993
Adjusted EBITDA									23,119	25,339	9,479
Refined products terminals and storage
Reportable Segments
Revenues									23,227	23,287	24,011
Adjusted EBITDA									10,867	10,723	16,100
NGL distribution and sales
Reportable Segments
Revenues									176,831	206,896	179,865
Adjusted EBITDA									30,896	15,511	15,518
Operating segment | Crude oil pipelines and storage
Reportable Segments
Cost of sales, excluding depreciation and amortization									445,027	459,183	167,744
Operating expense									9,238	7,928	7,405
Depreciation and amortization									20,356	17,240	10,335
Capital expenditures									42,919	36,691	4,410
Operating segment | Refined products terminals and storage
Reportable Segments
Cost of sales, excluding depreciation and amortization									8,649	6,453	4,683
Operating expense									2,980	4,602	2,464
Depreciation and amortization									6,830	5,911	6,162
Capital expenditures									8,002	2,489	4,482
Operating segment | NGL distribution and sales
Reportable Segments
Cost of sales, excluding depreciation and amortization									76,618	126,686	105,488
Operating expense									57,200	52,109	47,307
Depreciation and amortization									18,628	16,163	13,981
Capital expenditures									18,587	16,557	16,009
Amounts not included in segment Adjusted EBITDA
Reportable Segments
Cost of sales, excluding depreciation and amortization									(2,818)	13,360	(1,111)
Operating expense									(41)	945	552
Corporate and other
Reportable Segments
Depreciation and amortization									1,038	916	509
Capital expenditures									$ 1,503	$ 1,141	$ 1,927

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Reportable Segments (EBITDA) (Details) - USD ($)	1 Months Ended	3 Months Ended								12 Months Ended			24 Months Ended
	Aug. 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Reconciliation of total Adjusted EBITDA from reportable segments to net income (loss) from continuing operations
Total Adjusted EBITDA from reportable segments										$ 64,882,000	$ 51,573,000	$ 41,097,000
Other expenses not allocated to reportable segments										(19,226,000)	(24,924,000)	(27,396,000)
Depreciation and amortization										(46,852,000)	(40,230,000)	(30,987,000)
Goodwill impairment										(29,896,000)			$ 0
Interest expense										(5,375,000)	(8,981,000)	(8,245,000)
Loss on extinguishment of debt											(1,634,000)
Income tax expense										(754,000)	(300,000)	(208,000)
Loss on disposal of assets, net										(909,000)	(1,137,000)	(1,492,000)
Unit-based compensation										(1,217,000)	(1,658,000)	(790,000)
Total loss on commodity derivatives										(3,057,000)	(13,762,000)	902,000
Net cash payments for commodity derivatives settled during the period										14,821,000	1,071,000	209,000
Early settlement of commodity derivatives	$ (8,745,000)									(8,745,000)
Corporate overhead support from general partner										(5,500,000)
Transaction costs and other										(1,877,000)	(3,766,000)	(1,286,000)
LOSS FROM CONTINUING OPERATIONS		$ (32,097,000)	$ (7,201,000)	$ (5,479,000)	$ 1,072,000	$ (18,125,000)	$ (6,410,000)	$ (10,738,000)	$ (8,475,000)	$ (43,705,000)	$ (43,748,000)	$ (28,196,000)

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Reportable Segments (Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Reportable Segments
Total Assets	$ 735,259	$ 813,173
Operating segment | Crude oil pipelines and storage
Reportable Segments
Total Assets	408,304	451,518
Operating segment | Refined products terminals and storage
Reportable Segments
Total Assets	131,931	131,923
Operating segment | NGL distribution and sales
Reportable Segments
Total Assets	173,558	170,904
Corporate and other
Reportable Segments
Total Assets	12,092	21,958
Held-for-sale
Reportable Segments
Total Assets	$ 9,374	$ 36,870

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Related Parties (JD Development) (Details) - JP Development - USD ($)	12 Months Ended			36 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Nov. 05, 2013
Related Party Transactions
Monthly fee received				$ 50,000
Amount of reduction in general and administrative expenses				600,000
Related Party Transaction Additional Fee Received	$ 228,000
Receivable balance due from related party	7,933,000	$ 7,968,000		$ 7,933,000
Face amount					$ 1,000,000
Interest rate (as a percent)					4.75%
Crude oil supply and logistics
Related Party Transactions
Pipeline tariff fees	$ 6,023,000	$ 8,875,000	$ 8,514,000

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Related Parties (Units issued) (Details) - USD ($)				12 Months Ended
	Oct. 07, 2014	Mar. 28, 2014	Feb. 12, 2014	Dec. 31, 2014	Dec. 31, 2013
Related Party Transactions
Proceeds from issuance of common units				$ 262,638,000	$ 3,128,000
Proceeds from issuance of preferred units				40,000,000
Amount of redemption of preferred units				$ 42,436,000
Series D Preferred Unit
Related Party Transactions
Amount of redemption of preferred units	$ 42,436,000
JP Development | Class C Common Unit
Related Party Transactions
Units issued in private placements (in units)					88,114
Proceeds from issuance of common units					$ 3,128,000
Lonestar | Series D Preferred Unit
Related Party Transactions
Units issued in private placements (in units)		1,818,182
Proceeds from issuance of preferred units		$ 40,000,000
Lonestar | Class A Common Unit
Related Party Transactions
Units issued in private placements (in units)			363,636
Proceeds from issuance of common units			$ 8,000,000

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Related Parties (Other) (Details)	1 Months Ended	11 Months Ended	12 Months Ended			30 Months Ended
	Dec. 31, 2015 USD ($)	Nov. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2015 USD ($) employee
Related Party Transactions
Corporate overhead support from general partner			$ 5,500,000
Number of employees | employee						0
TAC | Refined products terminals and storage
Related Party Transactions
Receivable balance due from related party	$ 40,000		40,000	$ 38,000		$ 40,000
Revenue from related party				8,952,000	$ 14,473,000
TAC | NGL distribution and sales
Related Party Transactions
Refined product purchases			$ 1,124,000	1,964,000
Mr. Greg Arnold
Related Party Transactions
Equity Interest Ownership Percentage			5.00%
CAMS Bluewire
Related Party Transactions
Amount paid			$ 132,000	422,000	$ 691,000
Payable balance due to related party				32,000
Republic Midstream, LLC
Related Party Transactions
Receivable balance due from related party	646,000		646,000	297,000		646,000
Monthly fee received	75,000	$ 58,000
Amount of reduction in general and administrative expenses			712,000	297,000
Republic Midstream, LLC | Crude oil pipelines and storage
Related Party Transactions
Revenue from related party			3,049,000
ArcLight Capital Partners LLC
Related Party Transactions
Deemed contribution			2,568,000
Corporate overhead support from general partner			5,500,000
GP II
Related Party Transactions
Receivable balance due from related party	$ 4,000		$ 4,000	$ 2,205,000		$ 4,000

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Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Total revenues	$ 153,205	$ 154,641	$ 199,448	$ 173,291	$ 206,266	$ 213,922	$ 175,008	$ 130,958	$ 680,585	$ 726,154	$ 390,869
Operating (loss) income	(31,412)	(5,877)	(4,204)	2,185	(16,115)	(4,413)	(8,540)	(3,773)	(39,308)	(32,841)	(20,630)
Loss from continuing operations	(32,097)	(7,201)	(5,479)	1,072	(18,125)	(6,410)	(10,738)	(8,475)	(43,705)	(43,748)	(28,196)
Loss from discontinued operations	(13,839)	(1,247)	542	(407)	(491)	800	(9,471)	(113)	(14,951)	(9,275)	13,975
Net income (loss)	$ (45,936)	$ (8,448)	$ (4,937)	$ 665	$ (18,616)	$ (5,610)	$ (20,209)	$ (8,588)	$ (58,656)	$ (53,023)	$ (14,221)
Basic and diluted loss per unit
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax					$ (0.51)
Basic and diluted total (in dollars per unit)					(0.51)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax					$ (0.52)
Common
Basic and diluted loss per unit
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ (1.26)	$ (0.23)	$ (0.13)	$ 0.02					$ (1.60)	$ (0.51)
Basic and diluted total (in dollars per unit)	(1.26)	(0.23)	(0.13)	0.02					(1.60)	(0.51)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	(0.88)	(0.19)	(0.15)	0.03					(1.19)	(0.52)
Subordinated
Basic and diluted loss per unit
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	(1.26)	(0.23)	(0.14)	0.02					(1.61)	(0.51)
Basic and diluted total (in dollars per unit)	(1.26)	(0.23)	(0.14)	0.02					(1.61)	(0.51)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ (0.88)	$ (0.20)	$ (0.15)	$ 0.03					$ (1.20)	$ (0.52)