Quarterly Report (10-q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2016

☐ 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 organization)		(I.R.S. Employer Identification No.)

600 East Las Colinas Blvd
Suite 2000

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


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 Act). YES ☐ NO ☒

At August 1, 2016, there were 18,529,541 common units and 18,124,560 subordinated units outstanding.

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9
PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statements of Cash Flows	7
	Condensed Consolidated Statement of Partners’ Capital	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	43

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	44
Item 6.	Exhibits	45
SIGNATURES		46

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PART I FINANCIAL INFORMATION

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q (this “report” or this “Form 10-Q”) to “JP Energy Partners,” “the Partnership,” “we,” “our,” “us,” or like terms refer to JP Energy Partners LP and its subsidiaries, and references to “our general partner” refer to JP Energy GP II LLC, our general partner. References to “our sponsor” or “Lonestar” refer to Lonestar Midstream Holdings, LLC, which, together with JP Energy GP LLC, CB Capital Holdings II, LLC and the Greg Alan Arnold Separate Property Trust, entities owned by certain members of our management, owns and controls our general partner. References to “ArcLight Capital” refer to ArcLight Capital Partners, LLC and references to “ArcLight Fund V” refer to ArcLight Energy Partners Fund V, L.P. References to “ArcLight” refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.

Forward-Looking Statements

Certain statements and information in this Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future 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;

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

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 competitive conditions in our industry;

 changes in the long-term supply or production 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;

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

 other factors discussed elsewhere in this Form 10-Q 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 undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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Item 1. Financial Statements

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
	2016		2015

	(in thousands, except unit data)
ASSETS
Current assets
Cash and cash equivalents	$	1,287	$	1,987
Accounts receivable, net		45,655		60,519
Receivables from related parties		694		8,624
Inventory		9,053		4,786
Prepaid expenses and other current assets		6,153		4,168
Current assets of discontinued operations held for sale		—		2,730
Total Current Assets		62,842		82,814

Non-current assets
Property, plant and equipment, net		285,308		291,454
Goodwill		216,692		216,692
Intangible assets, net		126,283		134,432
Deferred financing costs and other assets, net		2,734		3,223
Noncurrent assets of discontinued operations held for sale		—		6,644
Total Non-Current Assets		631,017		652,445
Total Assets	$	693,859	$	735,259

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	34,134	$	45,933
Payables to related parties		98		—
Accrued liabilities		15,982		15,260
Capital leases and short-term debt		41		107
Customer deposits and advances		2,580		3,742
Current portion of long-term debt		1,134		454
Current liabilities of discontinued operations held for sale		—		640
Total Current Liabilities		53,969		66,136

Non-current liabilities
Long-term debt		158,000		162,740
Other long-term liabilities		1,795		1,463
Total Liabilities		213,764		230,339

Commitments and Contingencies

Partners’ capital
General Partner		9,568		5,568
Common units (22,119,170 units authorized; 18,529,541 and 18,465,320 units issued and outstanding as of June 30, 2016 and December 31, 2015, respectively)		252,368		266,691
Subordinated units (18,197,249 units authorized; 18,124,560 and 18,127,678 units issued and outstanding as of June 30, 2016 and December 31, 2015, respectively)		218,159		232,661
Total Partners’ Capital		480,095		504,920
Total Liabilities and Partners’ Capital	$	693,859	$	735,259

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015

	(in thousands, except unit and per unit data)
REVENUES
Crude oil sales	$	82,242	$	147,497	$	123,388	$	253,452
Gathering, transportation and storage fees		4,952		6,647		10,781		13,593
Gathering, transportation and storage fees - related parties		814		280		1,845		280
NGL and refined product sales		36,020		38,071		78,767		92,255
NGL and refined product sales - related parties		—		—		244		—
Refined products terminals and storage fees		3,352		3,068		6,450		6,176
Other revenues		3,389		3,885		6,785		6,983
Total revenues		130,769		199,448		228,260		372,739

COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		93,580		162,398		150,740		292,314
Operating expense		16,159		17,649		32,489		33,902
General and administrative		9,441		10,815		20,648		24,876
Depreciation and amortization		11,629		11,518		23,165		22,281
Loss on disposal of assets, net		558		1,272		1,690		1,385
Total costs and expenses		131,367		203,652		228,732		374,758

OPERATING LOSS		(598)		(4,204)		(472)		(2,019)

OTHER INCOME (EXPENSE)
Interest expense		(2,103)		(1,382)		(4,533)		(2,497)
Other income, net		496		336		527		360

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(2,205)		(5,250)		(4,478)		(4,156)

Income tax expense		(160)		(229)		(576)		(251)

LOSS FROM CONTINUING OPERATIONS		(2,365)		(5,479)		(5,054)		(4,407)

DISCONTINUED OPERATIONS
Net income (loss) from discontinued operations		—		542		(539)		135

NET LOSS	$	(2,365)	$	(4,937)	$	(5,593)	$	(4,272)

Basic and diluted loss per unit
Net loss from continuing operations allocated to common units	$	(1,133)		(2,692)	$	(2,452)	$	(2,137)
Net loss allocated to common units		(1,133)		(2,419)	$	(2,724)	$	(2,069)
Weighted average number of common units outstanding - basic		18,528,554		18,356,902		18,497,417		18,281,786
Weighted average number of common units outstanding - diluted		18,528,554		18,816,263		18,497,417		18,520,300
Basic and diluted net loss from continuing operations per common unit	$	(0.06)		(0.15)	$	(0.13)	$	(0.12)
Basic and diluted net loss per common unit		(0.06)		(0.13)	$	(0.15)	$	(0.11)

Net loss from continuing operations allocated to subordinated units	$	(1,232)		(2,787)	$	(2,602)	$	(2,270)
Net loss allocated to subordinated units		(1,232)		(2,518)	$	(2,869)	$	(2,203)
Weighted average number of subordinated units outstanding - basic and diluted	$	18,124,817		18,149,629		18,125,697		18,167,625
Basic and diluted net loss from continuing operations per subordinated unit		(0.07)		(0.15)	$	(0.14)	$	(0.12)
Basic and diluted net loss per subordinated unit		(0.07)		(0.14)	$	(0.16)	$	(0.12)

Distributions declared per common and subordinated unit	$	0.325	$	0.325	$	0.65	$	0.65

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2016		2015
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(5,593)	$	(4,272)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:
Depreciation and amortization		23,376		23,425
Derivative valuation changes		1,482		(3,602)
Amortization of deferred financing costs		482		455
Unit-based compensation expenses		942		552
Loss on disposal of assets		1,576		1,409
Bad debt expense		(61)		692
Other non-cash items		(423)		(186)
Changes in working capital, net of acquired assets and liabilities:
Accounts receivable		14,415		14,682
Receivables from related parties		7,930		2,159
Inventory		(5,204)		(9,292)
Prepaid expenses and other current assets		(1,998)		(5,191)
Accounts payable and other accrued liabilities		(9,582)		1,054
Payables to related parties		98		—
Customer deposits and advances		(652)		(2,524)
Changes in other assets and liabilities		196		(39)
Corporate overhead support from general partner		4,000		—
NET CASH PROVIDED BY OPERATING ACTIVITIES		30,984		19,322

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(14,416)		(32,237)
Acquisitions of businesses		—		(12,475)
Proceeds received from sale of assets		11,297		1,001
NET CASH USED IN INVESTING ACTIVITIES		(3,119)		(43,711)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving line of credit		33,000		70,000
Payments on revolving line of credit		(37,000)		(23,000)
Payments on long-term debt and capital leases		(203)		(209)
Distributions to unitholders		(24,015)		(23,028)
Tax withholding on unit-based vesting		(159)		(92)
Other		(188)		(186)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(28,565)		23,485

Net change in cash and cash equivalents		(700)		(904)
Cash and cash equivalents balance, beginning of period		1,987		3,325
Cash and cash equivalents balance, end of period	$	1,287	$	2,421

SUPPLEMENTAL DISCLOSURES:
Non-cash investing and financing transactions:
Accrued capital expenditures	$	1,635	$	6,496
Contributions from general partner		4,000		—
Acquisitions funded by issuance of units		—		3,442
Payable due to seller		—		86

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)


	Units
	Common		Subordinated		Total

Balance - December 31, 2015		18,465,320		18,127,678		36,592,998

Issuance of units under LTIP, net of forfeitures		64,221		(3,118)		61,103
Balance - June 30, 2016		18,529,541		18,124,560		36,654,101


					General
	Common		Subordinated		Partner		Total
	(in thousands)
Balance - December 31, 2015	$	266,691	$	232,661	$	5,568	$	504,920

Unit-based compensation		787		155		—		942
Unit forfeitures and tax withholdings		(149)		(10)		—		(159)
Distributions to unitholders		(12,237)		(11,778)		—		(24,015)
Contributions from general partner		—		—		4,000		4,000
Net loss		(2,724)		(2,869)		—		(5,593)

Balance - June 30, 2016	$	252,368	$	218,159	$	9,568	$	480,095

See accompanying notes to condensed consolidated financial statements.

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JP ENERGY PARTNERS LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Business and Basis of Presentation

Business. The unaudited condensed consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries. All 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. We completed our initial public offering in October 2014. 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 .

Basis of Presentation . Our unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying unaudited condensed consolidated financial statements.

The results of operations for the three and six months ended June 30, 2016 are not necessarily indicative of results expected for the full year ending December 31, 2016. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair statement of the financial position and results of operations for such interim periods in accordance with GAAP. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. These unaudited condensed consolidated interim financial statements and the notes thereto should be read in conjunction with our audited consolidated financial statements and the related notes for the year ended December 31, 2015 included in our Annual Report on Form 10-K filed with the SEC on February 29, 2016.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

2. Summary of Significant Accounting Policies

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.

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

Our other financial instruments consist primarily of cash and cash equivalents and long-term debt. The fair value of long-term debt approximates the carrying value as the underlying instruments are at rates similar to current rates offered to us for debt with the same remaining maturities.

Accounts Receivable . Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the condensed consolidated statements of operations. The allowance for doubtful accounts was $887,000 and $1,217,000 as of June 30, 201 6 and December 31, 2015, respectively.

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

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

Crude Oil Pipelines and Storage. The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. We enter into outright purchase and sale 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 for 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 purchase and sale 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 trucking transportation services to third party customers.

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

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

Comprehensive Loss . For the three and six months ended June 30, 2016 and 2015, comprehensive loss was equal to net loss.

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Recent Accounting Pronouncements.

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (ASC 842). Lessees will need to recognize almost all leases on their balance sheet as a right-of-use asset and a lease liability. It will be critical to identify leases embedded in a contract to avoid misstating the lessee’s balance sheet. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Classification will be based on criteria that are largely similar to those applied in current lease accounting, but without explicit bright lines. ASU 2016-02 is effective for public companies for annual reporting periods beginning after December 15, 2018 and interim periods within those fiscal years. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

In January 2016, the FASB issued 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 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 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

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application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). In August 2015, the FASB issued ASU No. 2015-14, Update Revenue from Contracts with Customers (Topic 606), which defers the effective date of ASU 2014-09 for public and non-public entities reporting under U.S. GAAP for one year. The FASB also decided to permit entities to early adopt the standard but adoption is not permitted earlier than the original effective date for public entities. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606) – Principal versus Agent Considerations (Reporting Gross versus Net), which is intended to provide clarity to principal versus agent considerations when it comes to revenue recognition related to ASU 2014-09. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606) – Identifying Performance Obligations and Licensing, which provides clarity to a few items for identifying performance obligations and licensing where the board had received feedback on the issuance of ASU 2014-09. Neither ASU 2016-08 nor 2016-10 is effective until ASU 2014-09 becomes effective. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

3. Discontinued Operations

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. As of December 31, 2015, the Mid-Continent Business met all the criteria to be classified as assets held for sale in accordance with ASC 360; therefore, we classified all the related assets and liabilities as held for sale in the condensed consolidated balance sheet at that date. The operating results of the Mid-Continent Business have been classified as discontinued operations for all periods presented in the condensed 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 condensed 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 for the three and six months ended June 30, 2016 and 2015 .

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Condensed Consolidated Statements of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
REVENUES
Crude oil sales	$	—	$	141,024	$	11,493	$	266,986
Gathering, transportation and storage fees		—		2		—		6
Other revenues		—		13		2		42
Total revenues		—		141,039		11,495		267,034

COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		—		139,460		11,687		264,434
Operating expense		—		296		172		654
General and administrative		—		166		31		587
Depreciation and amortization		—		569		211		1,145
Loss (gain) on disposal of assets, net		—		7		(114)		24
Total costs and expenses		—		140,498		11,987		266,844

OPERATING INCOME (LOSS)		—		541		(492)		190

OTHER INCOME (EXPENSE)
Interest expense		—		—		(47)		(57)
Other income, net		—		1		—		2

INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES		—		542		(539)		135

Income tax expense		—		—		—		—

NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS	$	—	$	542	$	(539)	$	135

Condensed Consolidated Balance Sheets

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


	December 31,
	2015
	(in thousands)
ASSETS
Current assets
Inventory	$	2,692
Prepaid expenses and other current assets		38
Total Current assets of discontinued operations held for sale		2,730

Non-current assets
Property, plant and equipment, net		5,203
Intangible assets, net		1,138
Deferred financing costs and other assets, net		303
Total Non-current assets of discontinued operations held for sale		6,644
Total Assets of discontinued operations held for sale	$	9,374

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:


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
Depreciation	$	—	$	317	$	115	$	625
Amortization		—		252		96		520
Capital expenditures		—		155		—		373

Other operating noncash items related to discontinued operations:
Derivative valuation changes	$	—	$	777	$	—	$	1,413
(Gain) loss on disposal of assets		—		7		(114)		24

4. Net Income per Unit

Net income per unit applicable to limited partner common units and to limited partner subordinated units is computed by dividing the respective limited partners’ interest in net income for the periods subsequent to the IPO by the weighted-average number of common units and subordinated units outstanding for the period. Income per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships (“MLPs”) when incentive distribution rights (“IDRs”) and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. Diluted net income per unit includes the effects of potentially dilutive units on our common units, consisting of unvested phantom units. Basic and diluted net income per unit applicable to limited partners holding subordinated units are the same because there are no potentially dilutive subordinated units outstanding. For the three and six months ended June 30, 2016, diluted loss per unit was equal to basic loss per unit because the outstanding phantom units of 617,317 and 500,547, respectively, were antidilutive.

On July 25, 2016, the Board of Directors of our general partner declared a cash distribution for the second quarter of 2016 of $0.325 per common unit and subordinated unit. The distribution will be paid on August 12, 2016 to unitholders of record as of August 5, 2016.

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The following tables illustrate our calculation of net (loss) income per common and subordinated unit for the three and six months ended June 30, 2016 and 2015:


	Three Months Ended June 30, 2016						Three Months Ended June 30, 2015
	Common Units		Subordinated Units		Total		Common Units		Subordinated Units		Total
	(in thousands except for unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	6,147	$	5,890	$	12,037	$	6,091	$	5,895	$	11,986
Distributions in excess of net income		(7,280)		(7,122)		(14,402)		(8,783)		(8,682)		(17,465)
Net loss from continuing operations attributable to the limited partners	$	(1,133)	$	(1,232)	$	(2,365)	$	(2,692)	$	(2,787)	$	(5,479)

Net income from discontinued operations attributable to the limited partners		—		—		—		273		269		542
Net loss attributable to the limited partners	$	(1,133)	$	(1,232)	$	(2,365)	$	(2,419)	$	(2,518)	$	(4,937)


Weighted average units outstanding:
Basic		18,528,554		18,124,817		36,653,371		18,356,902		18,149,629		36,506,531
Dilutive effect of unvested phantom units		—		—		—		459,361		—		459,361
Diluted		18,528,554		18,124,817		36,653,371		18,816,263		18,149,629		36,965,892
Net (loss) income per unit:
Basic and diluted from continuing operations	$	(0.06)	$	(0.07)			$	(0.15)	$	(0.15)
Basic and diluted from discontinued operations	$	—	$	—			$	0.02	$	0.01
Basic and diluted total	$	(0.06)	$	(0.07)			$	(0.13)	$	(0.14)


	Six months ended June 30, 2016						Six Months Ended June 30, 2015
	Common Units		Subordinated Units		Total		Common Units		Subordinated Units		Total
	(in thousands except for unit and per unit data)
Net loss from continuing operations attributable to the limited partners:
Distribution declared	$	12,227	$	11,782	$	24,009	$	12,012	$	11,790	$	23,802
Distributions in excess of net income		(14,679)		(14,384)		(29,063)		(14,149)		(14,060)		(28,209)
Net loss from continuing operations attributable to the limited partners	$	(2,452)	$	(2,602)	$	(5,054)	$	(2,137)	$	(2,270)	$	(4,407)

Net (loss) income from discontinued operations attributable to the limited partners		(272)		(267)		(539)		68		67		135
Net loss attributable to the limited partners	$	(2,724)	$	(2,869)	$	(5,593)	$	(2,069)	$	(2,203)	$	(4,272)

Weighted average units outstanding:
Basic		18,497,417		18,125,697		36,623,114		18,281,786		18,167,625		36,449,411
Dilutive effect of unvested phantom units		—		—		—		238,514		—		238,514
Diluted		18,497,417		18,125,697		36,623,114		18,520,300		18,167,625		36,687,925
Net (loss) income per unit:
Basic and diluted from continuing operations	$	(0.13)	$	(0.14)			$	(0.12)	$	(0.12)
Basic and diluted from discontinued operations	$	(0.02)	$	(0.02)			$	0.01	$	0.00
Basic and diluted total	$	(0.15)	$	(0.16)			$	(0.11)	$	(0.12)

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5. Inventory

Inventory consists of the following as of June 30, 2016 and December 31, 2015:


	June 30,		December 31,
	2016		2015
	(in thousands)
Crude oil	$	4,066	$	338
NGLs		2,614		2,364
Refined products		290		430
Materials, supplies and equipment		2,083		1,654
Total inventory	$	9,053	$	4,786

6. Long-Term Debt

Long-term debt consists of the following at June 30, 2016 and December 31, 2015:


	June 30,		December 31,
	2016		2015
	(in thousands)
Bank of America revolving loan	$	158,000	$	162,000
HBH note payable		1,015		1,077
Non-compete notes payable		119		117
Total long-term debt	$	159,134	$	163,194
Less: Current maturities		(1,134)		(454)
Total long-term debt, net of current maturities	$	158,000	$	162,740

Bank of America Credit Agreement . We have a $275,000,000 revolving credit facility with Bank of America, N.A. (the “BOA Credit Agreement”) that matures on February 12, 2019. As of June 30, 2016 , the unused portion of our revolving credit facility was $102,250,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $14,750,000 at June 30, 2016 . The BOA Credit Agreement contains various restrictive covenants and compliance requirements. We were in compliance with all covenants as of June 30, 2016.

7. 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. 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, propane and refined products, 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 and refined product 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 sales

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prices in future periods. These forward sale contracts were intended to mitigate the effect of any decline in crude oil prices, but did 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 related to the marketing assets in our Mid-Continent Business (see Note 3), the fair values of the forward contracts were classified as held for sale in the consolidated balance sheets. As of December 31, 2015, the fair value of the Mid-Continent forward contracts was $630,000 and was included in current liabilities of discontinued operations held for sale in the condensed consolidated balance sheets.

The following table summarizes the net notional volume purchases (sales) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the NPNS exception as of June 30, 2016 and December 31, 2015, none of which were designated as hedges for accounting purposes.


	June 30, 2016		December 31, 2015
	Notional Volume	Maturity	Notional Volume	Maturity
Swaps :
Propane (Gallons)	4,440,589	July 2016 - Dec 2017	8,614,631	Jan 2016 - July 2017
Crude Oil (Barrels)	(90,000)	July 2016 - Nov 2016	(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 effectively change the variable-rate cash flow exposure on the debt obligations to fixed rates. Under the terms of the interest rate swaps, we receive variable interest rate payments and make fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that is swapped. As of June 30, 2016, our outstanding interest rate swap contracts contained a notional amount of $100,000,000 with maturity dates ranging from July 2016 to January 2019. There were no outstanding interest rate swap agreements as of December 31, 2015.

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

Fair Value of Derivative Instruments. We measure derivative instruments at fair value using the income approach, which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations primarily utilize 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

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designated as hedging instruments. The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015.


		Asset Derivatives				Liability Derivatives
		June 30,		December 31,		June 30,		December 31,
	Balance Sheet Location	2016		2015		2016		2015

		(in thousands)
Commodity swaps	Prepaid expenses and other current assets	$	955	$	92	$	—	$	—
Commodity swaps	Accrued liabilities		—		—		(1,556)		(450)
Commodity swaps	Deferred financing costs and other assets, net		16		—		—		—
Commodity swaps	Other long-term liabilities		—		—		—		(24)
Interest rate swaps	Accrued liabilities		—		—		(387)		—
Interest rate swaps	Other long-term liabilities		—		—		(892)		—

The following tables present the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015 that are subject to enforceable master netting arrangements.


	As of June 30, 2016
	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented in the Balance Sheet		Financial Collateral		Net Amount
	(in thousands)
Derivative Assets:
Derivative contracts - current	$	955	$	(955)	$	—	$	—	$	—
Derivative contracts - noncurrent		16		(16)		—		—		—
Derivative Liabilities:
Derivative contracts - current	$	1,943	$	(955)	$	988	$	—	$	988
Derivative contracts - noncurrent		892		(16)		876		—		876


	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

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

Amount of Loss Recognized in Income on Derivatives

Location of Loss Recognized in

Three Months Ended

Six Months Ended

Income on Derivatives

June 30, 2016

June 30, 2015

June 30, 2016

June 30, 2015

(in thousands)

Commodity derivatives (swaps)

Cost of sales

(601)

(1,254)

(736)

(1,119)

Interest rate swaps

Interest expense

(509)

(4)

(1,311)

(26)

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The following table presents the amounts recognized with respect to derivative instruments related to the Mid-Continent Business, which have been included in amounts classified as discontinued operations in the condensed consolidated statements of operations .


	Three Months Ended				Six Months Ended
	June 30, 2016		June 30, 2015		June 30, 2016		June 30, 2015
	(in thousands)

(Loss) gain recognized on derivatives from discontinued operations	$	—	$	(4,437)	$	361	$	(3,801)

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

8. Partners’ Capital and Distributions

Distributions . 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, subject to certain terms and conditions. The following table shows the distributions declared by us subsequent to December 31, 2015:


Quarter Ended	Record Date	Payment Date	Cash Distributions (per unit)
December 31, 2015	February 5, 2016	February 12, 2016	$	0.325
March 31, 2016	May 6, 2016	May 13, 2016	$	0.325
June 30, 2016	August 5, 2016	August 12, 2016	$	0.325

9. Unit-Based Compensation

Long-Term Incentive Plan and Phantom Units. The 2014 Long-Term Incentive Plan (“LTIP”) for our employees, directors and consultants authorizes grants of up to 3,642,700 common units in the aggregate. Our phantom units issued under our LTIP are primarily composed of two types of grants: (1) service condition grants with vesting over three years in equal annual installments; and (2) service condition grants with cliff vesting on April 1, 2018. Distributions related to these unvested phantom units 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 six months ended June 30, 2016:



Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period		392,420	$	12.99
Service condition grants		362,743		5.33
Vested service condition		(92,430)		11.18
Forfeited service condition		(62,970)		11.49
Total outstanding at end of period		599,763		8.79

We expect to recognize $3.3 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 33% in calculating the unit-based compensation expense.

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

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The following table presents restricted (non-vested) common and subordinated units activity for the six months ended June 30, 2016:


	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		6,424	$	25.91		26,216	$	25.91
Vested - service condition		(2,482)		27.74		(10,129)		27.74
Outstanding at the end of period		3,942		24.76		16,087		24.76

We expect to recognize $367,000 of compensation expense related to restricted (non-vested) common and subordinated units over a weighted average period of 1.3 years.

Total unit-based compensation expenses related to our phantom units and restricted (non-vested) common and subordinated units were $383,000 and $97,000 for the three months ended June 30, 2016 and 2015, respectively, and $942,000 and $503,000 for the six months ended June 30, 2016 and 2015, respectively.

10. Commitments and Contingencies

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

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

Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting 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 June 30, 2016 and December 31, 2015, we had no significant environmental matters .

11. 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

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have presented segment information for the three and six months ended June 30, 2015 to reflect this new segment adjustment.

Crude oil pipelines and storage. The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin consisting of approximately 15 6 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 shell storage capacity. We also own a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.

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 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 an aggregate storage capacity of 1.3 million barrels in 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 in 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. In the second quarter of 2016, we completed the connection of the North Little Rock terminal to Magellan’s Little Rock Pipeline. Following the connection, the North Little Rock terminal allows delivery from Enterprise TE Products Pipeline Company LLC and Magellan’s Little Rock Pipeline. The Caddo Mills terminal is primarily served by the Explorer Pipeline.

NGL distribution and sales. The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange; (ii) NGL sales through our retail, commercial and wholesale distribution business; and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 4 6 states through a network of approximately 20,000 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the United States, we sell NGLs to retailers, wholesalers, industrial end users and commercial and residential customers. We also own a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.

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

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 .

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The following tables reflect certain financial data for each reportable segment for the three and six months ended June 30, 2016 and 2015.


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
External Revenues:
Crude oil pipelines and storage	$	87,511	$	153,433	$	134,399	$	264,977
Refined products terminals and storage		8,518		4,703		14,507		10,211
NGL distribution and sales		34,740		41,312		79,354		97,551
Total revenues	$	130,769	$	199,448	$	228,260	$	372,739

Cost of Sales, excluding depreciation and amortization:
Crude oil pipelines and storage	$	77,899	$	143,613	$	116,871	$	246,826
Refined products terminals and storage		3,772		1,292		6,057		3,167
NGL distribution and sales		12,425		19,074		28,734		47,028
Amounts not included in segment Adjusted EBITDA		(516)		(1,581)		(922)		(4,707)
Total cost of sales, excluding depreciation and amortization	$	93,580	$	162,398	$	150,740	$	292,314

Operating Expenses:
Crude oil pipelines and storage	$	2,027	$	2,623	$	4,264	$	5,272
Refined products terminals and storage		504		762		1,212		1,371
NGL distribution and sales		13,638		14,222		27,280		27,008
Amounts not included in segment Adjusted EBITDA		(10)		42		(267)		251
Total operating expenses	$	16,159	$	17,649	$	32,489	$	33,902

Adjusted EBITDA:
Crude oil pipelines and storage	$	6,917	$	6,547	$	11,731	$	11,430
Refined products terminals and storage		4,047		2,518		6,905		5,340
NGL distribution and sales		6,369		4,828		18,658		16,852
Total Adjusted EBITDA from reportable segments	$	17,333	$	13,893	$	37,294	$	33,622

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
Total Adjusted EBITDA from reportable segments	$	17,333	$	13,893	$	37,294	$	33,622
Other expenses not allocated to reportable segments		(2,452)		(6,120)		(7,860)		(13,310)
Depreciation and amortization		(11,629)		(11,518)		(23,165)		(22,281)
Interest expense		(2,103)		(1,382)		(4,533)		(2,497)
Loss on disposal of assets, net		(558)		(1,272)		(1,690)		(1,385)
Unit-based compensation		(383)		(97)		(942)		(503)
Total loss on commodity derivatives		(601)		(1,254)		(736)		(1,119)
Net cash payments for commodity derivatives settled during the period		144		2,835		532		6,027
Non-cash inventory costing adjustment		973		—		1,126		—
Corporate overhead support from general partner (1)		(3,500)		—		(5,000)		—
Transaction costs and other		571		(335)		496		(2,710)
Loss from continuing operations before income taxes	$	(2,205)	$	(5,250)	$	(4,478)	$	(4,156)

(1)

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

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Total assets for our reportable segments as of June 30, 2016 and December 31, 2015 were as follows:


	June 30,		December 31,
	2016		2015
	(in thousands)
Crude oil pipelines and storage	$	388,742	$	408,304
Refined products terminals and storage		132,056		131,931
NGL distribution and sales		158,863		173,558
Corporate and other		14,198		12,092
Discontinued operations held for sale		—		9,374
Total assets	$	693,859	$	735,259

12. Related Party Transactions

We performed certain management services for JP Development through January 2016. We received a monthly fee of $50,000 for these services, which reduced the general and administrative expenses on the condensed consolidated statements of operations by $150,000 for the three months ended June 30, 2015, and $50,000 and $300,000 for the six months ended June 30, 2016 and 2015, respectively.

Prior to February 2016, 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 $1,625,000 for the three months ended June 30, 2015 and $372,000 and $3,265,000 for the six months ended June 30, 2016 and 2015, respectively, which have been included in net loss from discontinued operations in the condensed consolidated statements of operations. As of December 31, 2015, we had a net receivable from JP Development of $7,933,000, 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 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 a result of the acquisition of the 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 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 the six months ended June 30, 2016. We did not sell refined products to TAC during the three months ended June 30, 2016 or during the three and six months ended June 30, 2015. Our revenue from TAC was $244,000 for the six months ended June 30, 2016, which is included in NGL and refined product sales – related parties in the condensed consolidated statements of operations.

Our NGL distribution and sales segment also purchases refined products from TAC. We paid $243,000 and $288,000 during the three months ended June 30, 2016 and 2015, respectively, and $462,000 and $514,000 during the six months ended June 30, 2016 and 2015, respectively, for refined product purchases from TAC, which are included in cost of sales on the condensed consolidated statements of operations.

Through April 2015, we entered into transactions with CAMS Bluewire, an entity in which ArcLight holds a non-controlling interest. CAMS Bluewire provided IT support for us. We paid $22,000 and $132,000 for the three and six months ended June 30, 2015, for IT support and consulting services, and for the purchases of IT equipment, which are included in operating expense, general and administrative and property, plant and equipment, net, in the condensed consolidated statements of operations and the condensed consolidated balance sheets.

We perform certain management services for Republic Midstream, LLC (“Republic”), an entity owned by ArcLight. We charged a monthly fee of approximately $58,000 for these services through November 2015. In December 2015, the monthly fee increased to $75,000. The monthly fee reduced the general and administrative expenses on the condensed consolidated statements of operations by $225,000 and $175,000 for the three months ended June 30, 2016

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and 2015, respectively, and $450,000 and $350,000 for the six months ended June 30, 2016 and 2015, respectively . During the second quarter of 2015, we began performing crude transportation and marketing services for Republic. We charged $814,000 and $280,000 in the three months ended June 30, 2016 and 2015, respectively, and $1,845,000 and $280,000 for the six months ended June 30, 2016 and 2015, respectively, for these services which are included in gathering, transportation and storage fees – related parties and crude oil sales – related parties on the condensed consolidated statements of operations. As of June 30, 2016 and December 31, 2015, we had a receivable balance due from Republic of $487,000 and $646,000, respectively, which is included in receivables from related parties in the condensed consolidated balance sheets.

During the three and six months ended June 30, 2016, our general partner agreed to absorb $3,500,000 and $5,000,000, respectively, of corporate overhead expenses incurred by us and not pass such expense through to us. We receive reimbursements for these expenses from our general partner in the quarters subsequent to when they were incurred, which was $1,500,000 and $4,000,000, respectively, for the three and six months ended June 30, 2016. In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In the second quarter of 2015, ArcLight agreed to reimburse us for certain professional fees we incurred. The total amounts paid on our behalf were $1,254,000 and $2,604,000 for the three and six months ended June 30, 2015, respectively, and were treated as deemed contributions from ArcLight.

We do not have any employees. The employees supporting our operations are employees of our general partner, and as such, we reimburse our general partner for payroll and other payroll-related expenses we incur.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited historical condensed consolidated financial statements and notes in “Item 1. Financial Statements” contained herein and our audited historical consolidated financial statements as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014, and 2013 included in our Annual Report on Form 10-K, as filed with the SEC on February 29, 2016 (our “2015 Form 10-K”). Among other things, those historical consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included in our 2015 Form 10-K. See also “Forward-Looking Statements.”

General

We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We completed our initial public offering in October 2014. 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 has been to focus on:

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

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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.

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 .

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 utilized the proceeds from the sale of the Mid-Continent Business to pay down a portion of our revolving credit facility. We continue to retain our crude oil storage operations in the Mid-Continent area of Oklahoma .

Recent Trends

Changes in Commodity Prices

Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $61.36 per barrel to a low of $26.19 per barrel during the period from January 1, 2015 through June 30, 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, including reserves in our areas of operation in the Midland Basin. Further declines in commodity prices of crude oil could have a negative impact on exploration, development and production activity, and, if sustained, could lead

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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 and increased competition for production volumes. 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 first quarter of 2016, 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 at year end 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 .

How We Evaluate Our Operations

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

Volumes and revenues

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

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amortization, by attempting to acquire the products which we use in each of our segments at times and prices which are most optimal based on our knowledge of the industry and the regions in which we operate .

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

Adjusted EBITDA and adjusted gross margin. Our management uses Adjusted EBITDA and adjusted gross margin to analyze our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gain (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).

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

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

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

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

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

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

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


	Three Months Ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(in thousands)
Reconciliation of Adjusted EBITDA to net loss
Net loss	$	(2,365)	$	(4,937)	$	(5,593)	$	(4,272)
Depreciation and amortization		11,629		11,518		23,165		22,281
Interest expense		2,103		1,382		4,533		2,497
Income tax expense		160		229		576		251
Loss on disposal of assets, net		558		1,272		1,690		1,385
Unit-based compensation		383		97		942		503
Total loss on commodity derivatives		601		1,254		736		1,119
Net cash payments for commodity derivatives settled during the period		(144)		(2,835)		(532)		(6,027)
Non-cash inventory costing adjustment		(973)		—		(1,126)		—
Corporate overhead support from general partner (1)		3,500		—		5,000		—
Transaction costs and other		(571)		335		(496)		2,710
Discontinued operations (2)		—		(1,257)		168		1,800
Adjusted EBITDA	$	14,881	$	7,058	$	29,063	$	22,247

(1)

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

(2)

In February 2016, we completed the sale of our Mid-Continent Business .


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
Reconciliation of adjusted gross margin to operating loss
Adjusted gross margin
Crude oil pipelines and storage	$	9,612	$	9,820	$	17,528	$	18,151
Refined products terminals and storage		4,746		3,411		8,450		7,044
NGL distribution and sales		22,315		22,238		50,620		50,523
Total Adjusted gross margin		36,673		35,469		76,598		75,718

Operating expenses		(16,159)		(17,649)		(32,489)		(33,902)
General and administrative		(9,441)		(10,815)		(20,648)		(24,876)
Depreciation and amortization		(11,629)		(11,518)		(23,165)		(22,281)
Loss on disposal of assets, net		(558)		(1,272)		(1,690)		(1,385)
Total loss on commodity derivatives		(601)		(1,254)		(736)		(1,119)
Net cash payments for commodity derivatives settled during the period		144		2,835		532		6,027
Non-cash inventory costing adjustment		973		—		1,126		—
Other non-cash items		—		—		—		(201)
Operating loss	$	(598)	$	(4,204)	$	(472)	$	(2,019)

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Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)
TOTAL REVENUES	$	130,769	$	199,448	$	228,260	$	372,739

COSTS AND EXPENSES
Cost of sales, excluding depreciation and amortization		93,580		162,398		150,740		292,314
Operating expense		16,159		17,649		32,489		33,902
General and administrative		9,441		10,815		20,648		24,876
Depreciation and amortization		11,629		11,518		23,165		22,281
Loss on disposal of assets, net		558		1,272		1,690		1,385
Total costs and expenses		131,367		203,652		228,732		374,758

OPERATING LOSS		(598)		(4,204)		(472)		(2,019)

OTHER INCOME (EXPENSE)
Interest expense		(2,103)		(1,382)		(4,533)		(2,497)
Other income, net		496		336		527		360

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(2,205)		(5,250)		(4,478)		(4,156)

Income tax expense		(160)		(229)		(576)		(251)
LOSS FROM CONTINUING OPERATIONS		(2,365)		(5,479)		(5,054)		(4,407)

DISCONTINUED OPERATIONS (1)
Net income (loss) from discontinued operations		—		542		(539)		135

NET LOSS	$	(2,365)	$	(4,937)	$	(5,593)	$	(4,272)

(1)

In February 2016, we completed the sale of our Mid-Continent Business .

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Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Consolidated Results


	Three Months Ended June 30,
	2016		2015		Variance

		(in thousands)
Segment Adjusted EBITDA
Crude oil pipelines and storage (1)	$	6,917	$	6,547	$	370
Refined products terminals and storage (1)		4,047		2,518		1,529
NGL distribution and sales (1)		6,369		4,828		1,541
Discontinued operations (2)		—		(715)		715
Corporate and other		(2,452)		(6,120)		3,668
Total Adjusted EBITDA		14,881		7,058		7,823
Depreciation and amortization		(11,629)		(11,518)		(111)
Interest expense		(2,103)		(1,382)		(721)
Income tax expense		(160)		(229)		69
Loss on disposal of assets, net		(558)		(1,272)		714
Unit-based compensation		(383)		(97)		(286)
Total loss on commodity derivatives		(601)		(1,254)		653
Net cash payments for commodity derivatives settled during the period		144		2,835		(2,691)
Non-cash inventory costing adjustment		973		—		973
Corporate overhead support from general partner		(3,500)		—		(3,500)
Transaction costs and other		571		(335)		906
Discontinued operations (2)		—		1,257		(1,257)
Net loss	$	(2,365)	$	(4,937)	$	2,572

(1)

See further analysis of Adjusted EBITDA of each reportable segment below.

(2)

In February 2016, we completed the sale of our Mid-Continent Business .

Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses decreased to $2.5 million for the three months ended June 30, 2016 from $6.1 million for the three months ended June 30, 2015. The decrease was primarily due to $3.5 million of expenses incurred by us during the three months ended June 30, 2016, that were absorbed by our general partner and not passed through to us.

Interest expense. Interest expense for the three months ended June 30, 2016 increased to $2.1 million from $1.4 million for the three months ended June 30, 2015. The increase was primarily due to non-cash losses on interest rate swaps and an increase in average outstanding borrowings under our revolving credit facility. Our interest rate swaps are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate swaps increased $0.5 million in the three months ended June 30 , 2016 compared to the three months ended June 30 , 2015 as a result of forward market interest rates decreasing. Our average outstanding borrowings increased from $136.8 million for the three months ended June 30, 2015 to $159.6 million for the three months ended June 30, 2016.

Loss on disposal of assets, net. The loss on disposal of assets, net for the three months ended June 30, 2016 was $0.6 million compared to $1.3 million for the three months ended June 30, 2015. The change is primarily due to a reduction in the amount of scrapped cylinders and valve assets in our propane cylinder exchange business.

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 primarily due to the more favorable position of our propane and crude hedges during the three months ended June 30, 2016 compared to the three months ended June 30, 2015 .

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Non-cash inventory costing adjustment. We use the first-in, first-out (“FIFO”) method to calculate the cost of our crude oil inventory. Occasionally, we physically hold the crude oil inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices) . The non-cash inventory costing adjustment reflects the difference between the actual purchase price for this crude oil inventory and the cost calculated under the FIFO method. As a result, we have excluded the $1.0 million non-cash inventory costing adjustment in calculating Adjusted EBITDA, which will result in realization of the actual cost of this inventory in the same period when the inventory is physically sold.

Corporate overhead support from general partner. Corporate overhead support from general partner of $3.5 million represents expenses incurred by us during the three months ended June 30, 2016, that were absorbed by our general partner and not passed through to us.

Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense, the total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period and non-cash inventory costing adjustments related to the discontinued operations previously owned by our crude oil pipelines and storage segment. Such amounts were $1.3 million in the three months ended June 30, 2015 primarily due to a $3.9 million non-cash inventory costing adjustment in the three months ended June 30, 2015. As noted above, we use the FIFO method to calculate the cost of our crude oil inventory. During the first quarter of 2015, we entered into several fixed price forward sale contracts that settled during the third and fourth quarters of 2015. We physically held the crude oil inventory associated with those forward sales contracts until the time of the sale. The non-cash inventory costing adjustment reflected the difference between the actual purchase price for the crude oil inventory and the cost calculated under the FIFO method. As a result, we excluded the $3.9 million non-cash inventory costing adjustment in calculating Adjusted EBITDA in the three months ended June 30, 2015, which resulted in realization of the actual cost of the inventory in the same period when the inventory was physically sold. This increase was partially offset by changes in the total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period of $2.0 million and depreciation and amortization expense of $0.6 million in the three months ended June 30, 2015.

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Segment Operating Results

Crude Oil Pipelines and Storage


	Three Months Ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
Crude oil pipeline throughput (Bbls/d) (1)		25,219		29,541		(4,322)
Crude oil sales (Bbls/d) (2)		25,400		33,349		(7,949)
Revenues:
Crude oil sales	$	82,242	$	147,497	$	(65,255)
Gathering, transportation and storage fees		4,947		5,387		(440)
Other revenues		322		549		(227)
Total Revenues		87,511		153,433		(65,922)
Cost of sales, excluding depreciation and amortization (3)		(77,899)		(143,613)		65,714
Adjusted gross margin		9,612		9,820		(208)
Operating expenses (3)		(2,027)		(2,623)		596
General and administrative		(668)		(650)		(18)
Segment Adjusted EBITDA	$	6,917	$	6,547	$	370

(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 and operating expenses for the purpose of calculating segment Adjusted EBITDA .

Volumes. Crude oil pipeline throughput volumes decreased to 25,219 barrels per day for the three months ended June 30, 2016 from 29,541 barrels per day for the three months ended June 30, 2015. Crude oil sales volumes decreased to 25,400 barrels per day for the three months ended June 30, 2016 from 33,349 barrels per day for the three months ended June 30, 2015. The decrease in crude oil pipeline throughput volumes is due to overall reduction in our customer crude oil production volumes in our areas of operation. The reduction in crude oil sales volumes is primarily due to lower crude oil production for the three months ended June 30, 2016 compared to the three months ended June 30, 2015.

Adjusted gross margin. Adjusted gross margin decreased to $9.6 million for the three months ended June 30, 2016 from $9.8 million for the three months ended June 30, 2015. The decrease was primarily due to a decrease in crude oil sales and throughput volumes of $1.0 million and $0.5 million, respectively, as explained above, partially offset by an increase in crude oil sales margin of $1.3 million due to improved cost efficiencies on trucked barrels.

Operating expenses. Operating expenses decreased to $2.0 million for the three months ended June 30, 2016 from $2.6 million for the three months ended June 30, 2015. The decrease was primarily due to reductions in personnel costs of $0.5 million from lower headcount.

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Refined Products Terminals and Storage


	Three Months Ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
Terminal and storage throughput (Bbls/d) (1)		58,655		61,073		(2,418)
Revenues:
Refined products sales	$	5,037	$	1,616	$	3,421
Refined products terminals and storage fees		3,481		3,087		394
Total Revenues		8,518		4,703		3,815
Cost of sales, excluding depreciation and amortization (2)		(3,772)		(1,292)		(2,480)
Adjusted gross margin		4,746		3,411		1,335
Operating expenses (2)		(504)		(762)		258
General and administrative		(196)		(132)		(64)
Other income		1		1		—
Segment Adjusted EBITDA	$	4,047	$	2,518	$	1,529

(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 and operating expenses for the purpose of calculating segment Adjusted EBITDA .

Volumes. Volumes decreased to 58,655 barrels per day for the three months ended June 30, 2016 from 61,073 for the three months ended June 30, 2015. The decrease was primarily due to increased competition in our areas of operations.

Revenues. Revenues increased to $8.5 million for the three months ended June 30, 2016 from $4.7 million for the three months ended June 30, 2015. The increase was primarily due to an increase in refined products sales revenue of $3.4 million related to timing of our sale of butane blending volumes in the three months ended June 30, 2016.

Cost of Sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization, increased to $3.8 million for the three months ended June 30, 2016 from $1.3 million for the three months ended June 30, 2015. The increase was primarily due to an increase in refined products sales volumes.

Operating expenses. Operating expenses decreased to $0.5 million for the three months ended June 30, 2016 from $0.8 million for the three months ended June 30, 2015. The decrease was primarily due to $0.2 million in expenses incurred in the three months ended June 30, 2015 related to inadvertent product releases.

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NGL Distribution and Sales


	Three Months Ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
NGL and refined product sales (Mgal/d) (1)		164		180		(16)
Revenues:
Gathering, transportation and storage fees	$	662	$	1,492	$	(830)
NGL and refined product sales		30,983		36,455		(5,472)
Other revenues		3,095		3,365		(270)
Total Revenues		34,740		41,312		(6,572)
Cost of sales, excluding depreciation and amortization (2)		(12,425)		(19,074)		6,649
Adjusted gross margin		22,315		22,238		77
Operating expenses (2)		(13,638)		(14,222)		584
General and administrative (2)		(2,306)		(3,217)		911
Other income, net		(2)		29		(31)
Segment Adjusted EBITDA	$	6,369	$	4,828	$	1,541

(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 remained relatively flat in the three months ended June 30, 2016 compared to the three months ended June 30, 2015. The increase in NGL and refined product sales margin was offset by a decrease in NGL and refined product sales volumes. The average NGL and refined products sales margin increased due to more favorable market conditions in the three months ended June 30, 2016 compared to the three months ended June 30, 2015 . The reduction in NGL and refined product sales volumes was primarily due to a decline in volumes associated with oilfield services as a result of lower exploration and production activity in the three months ended June 30, 2016, partially offset by an increase in volumes due to the acquisition of Southern Propane in May 2015.

Operating expenses. Operating expenses decreased to $13.6 million for the three months ended June 30, 2016 from $14.2 million for the three months ended June 30, 2015. The decrease was primarily due to a reduction in employee costs of $0.5 million related to a reduction in headcount .

General and administrative. General and administrative expenses decreased to $2.3 million for the three months ended June 30, 2016 from $3.2 million for the three months ended June 30, 2015 due to overall cost reduction efforts. The decrease is primarily due to a reduction in bad debt expense of $0.3 million from an improvement in collection efforts and lower personnel costs of $0.4 million related to reduction in headcount.

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Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Consolidated Results


	Six months ended June 30,
	2016		2015		Variance

	(in thousands)
Segment Adjusted EBITDA
Crude oil pipelines and storage (1)	$	11,731	$	11,430	$	301
Refined products terminals and storage (1)		6,905		5,340		1,565
NGL distribution and sales (1)		18,658		16,852		1,806
Discontinued operations (2)		(371)		1,935		(2,306)
Corporate and other		(7,860)		(13,310)		5,450
Total Adjusted EBITDA		29,063		22,247		6,816
Depreciation and amortization		(23,165)		(22,281)		(884)
Interest expense		(4,533)		(2,497)		(2,036)
Income tax expense		(576)		(251)		(325)
Loss on disposal of assets, net		(1,690)		(1,385)		(305)
Unit-based compensation		(942)		(503)		(439)
Total loss on commodity derivatives		(736)		(1,119)		383
Net cash payments for commodity derivatives settled during the period		532		6,027		(5,495)
Non-cash inventory costing adjustment		1,126		—		1,126
Corporate overhead support from general partner		(5,000)		—		(5,000)
Transaction costs and other		496		(2,710)		3,206
Discontinued operations (2)		(168)		(1,800)		1,632
Net loss	$	(5,593)	$	(4,272)	$	(1,321)

(1)

See further analysis of Adjusted EBITDA of each reportable segment below.

(2)

In February 2016, we completed the sale of our Mid-Continent Business.

Discontinued operations Adjusted EBITDA. Adjusted EBITDA related to discontinued operations included previously in our crude oil pipelines and storage segment decreased $2.3 million in the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The decrease was primarily due to a decrease in crude oil sales volumes and crude oil sales margin in our operations in the Mid-Continent region of Oklahoma and Kansas. We completed the sale of our Mid-Continent Business in February 2016.

Corporate and other Adjusted EBITDA. Corporate and other Adjusted EBITDA primarily represents corporate expenses not allocated to reportable segments. Such expenses decreased to $7.9 million for the six months ended June 30, 2016 from $13.3 million for the six months ended June 30, 2015. The decrease was primarily due to $5.0 million of expenses incurred by us during the six months ended June 30, 2016, that were absorbed by our general partner and not passed through to us, as well as a decrease in employee expenses of $0.5 million.

Depreciation and amortization expense . Depreciation and amortization expense for the six months ended June 30, 2016 increased to $23.2 million from $22.3 million for the six months ended June 30, 2015. The increase was primarily due to the expansions of our Silver Dollar Pipeline System throughout 2015. Our average depreciable asset base increased from $304.0 million during the six months ended June 30, 2015 to $354.0 million during the six months ended June 30, 2016.

Interest expense. Interest expense for the six months ended June 30, 2016 increased to $4.5 million from $2.5 million for the six months ended June 30, 2015. The increase was primarily due to non-cash losses on interest rate swaps and an increase in average outstanding borrowings under our revolving credit facility. Our interest rate swaps are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period.

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Losses on interest rate swaps increased $1.4 million in the six months ended June 30 , 2016 compared to the six months ended June 30 , 2015 as a result of forward market interest rates decreasing. Our average outstanding borrowings increased from $119.9 million for the six months ended June 30, 2015 to $158.6 million for the six months ended June 30, 2016.

Unit-based compensation. Unit-based compensation for the six months ended June 30, 2016 increased to $0.9 million from $0.5 million for the six months ended June 30, 2015 primarily due to the additional LTIP phantom units granted in the six months ended June 30, 2016.

Total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period. The reduction in both total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period are primarily due to the more favorable position of our propane and crude hedges during the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

Non-cash inventory costing adjustment. We use the FIFO method to calculate the cost of our crude oil inventory. Occasionally, we will physically hold the crude oil inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices) . The non-cash inventory costing adjustment reflects the difference between the actual purchase price for this crude oil inventory and the cost calculated under the FIFO method. As a result, we have excluded the $1.1 million non-cash inventory costing adjustment in calculating Adjusted EBITDA, which will result in realization of the actual cost of this inventory in the same period when the inventory is physically sold.

Corporate overhead support from general partner. Corporate overhead support from general partner of $5.0 million represents expenses incurred by us during the six months ended June 30, 2016, that were absorbed by our general partner and not passed through to us.

Discontinued operations. Discontinued operations primarily represents non-cash depreciation and amortization expense, the total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period, non-cash inventory costing adjustments and non-cash vacation expense related to the discontinued operations previously owned by our crude oil pipelines and storage segment. Such amounts decreased to $0.2 million in the six months ended June 30, 2016 from $1.8 million for the three months ended June 30, 2015 primarily due to changes in the total loss on commodity derivatives and net cash payments for commodity derivatives settled during the period of $1.4 million and reduction in depreciation and amortization expense of $0.9 million. In addition, non-cash vacation expense decreased $0.1 million in the six months ended June 30, 2016 compared to the six months ended June 30, 2015. These decreases are partially offset by a non-cash inventory costing adjustment of $1.0 million during the six months ended June 30, 2015. As noted above, we use the FIFO method to calculate the cost of our crude oil inventory. During the first quarter of 2015, we entered into several fixed price forward sale contracts that settled during the third and fourth quarters of 2015. We physically held the crude oil inventory associated with those forward sales contracts until the time of the sale. The non-cash inventory costing adjustment reflected the difference between the actual purchase price for the crude oil inventory and the cost calculated under the FIFO method. As a result, we excluded the $1.0 million non-cash inventory costing adjustment in calculating Adjusted EBITDA in the six months ended June 30, 2015, which resulted in realization of the actual cost of the inventory in the same period when the inventory was physically sold.

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Segment Operating Results

Crude Oil Pipelines and Storage


	Six months ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
Crude oil pipeline throughput (Bbls/d) (1)		25,188		28,939		(3,751)
Crude oil sales (Bbls/d) (2)		21,892		31,577		(9,685)
Revenues:
Crude oil sales	$	123,389	$	253,452	$	(130,063)
Gathering, transportation and storage fees		10,373		10,378		(5)
Other revenues		637		1,147		(510)
Total Revenues		134,399		264,977		(130,578)
Cost of sales, excluding depreciation and amortization (3)		(116,871)		(246,826)		129,955
Adjusted gross margin		17,528		18,151		(623)
Operating expenses (3)		(4,264)		(5,272)		1,008
General and administrative (3)		(1,533)		(1,449)		(84)
Segment Adjusted EBITDA	$	11,731	$	11,430	$	301

(1)

(2)

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

(3)

Volumes. Crude oil pipeline throughput volumes decreased to 25,188 barrels per day for the six months ended June 30, 2016 from 28,939 barrels per day for the six months ended June 30, 2015. Crude oil sales volumes decreased to 21,892 barrels per day for the six months ended June 30, 2016 from 31,577 barrels per day for the six months ended June 30, 2015. The decrease in crude oil pipeline throughput volumes is due to overall reduction in our customer crude oil production volumes in our areas of operation. The reduction in crude oil sales volumes is primarily due to the lower crude oil production for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

Adjusted gross margin. Adjusted gross margin decreased to $17.5 million for the six months ended June 30, 2016 from $18.2 million for the six months ended June 30, 2015. The decrease was primarily due to a decrease in crude oil sales and throughput volumes of $2.1 million and $0.8 million, respectively, as explained above, partially offset by an increase in crude oil sales margin of $2.1 million due to improved cost efficiencies on trucked barrels.

Operating expenses. Operating expenses decreased to $4.3 million for the six months ended June 30, 2016 from $5.3 million for the six months ended June 30, 2015. The decrease was primarily due to reductions in personnel costs of $1.2 million from lower headcount.

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Refined Products Terminals and Storage


	Six months ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
Terminal and storage throughput (Bbls/d) (1)		58,647		62,423		(3,776)
Revenues:
Refined products sales	$	7,739	$	3,860	$	3,879
Refined products terminals and storage fees		6,768		6,351		417
Total Revenues		14,507		10,211		4,296
Cost of sales, excluding depreciation and amortization (2)		(6,057)		(3,167)		(2,890)
Adjusted gross margin		8,450		7,044		1,406
Operating expenses (2)		(1,212)		(1,371)		159
General and administrative		(346)		(336)		(10)
Other income		13		3		10
Segment Adjusted EBITDA	$	6,905	$	5,340	$	1,565

(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 and operating expenses for the purpose of calculating segment Adjusted EBITDA .

Volumes. Volumes decreased to 58,647 barrels per day for the six months ended June 30, 2016 from 62,423 for the six months ended June 30, 2015. The decrease was primarily due to increased competition in our area of operations and a non-recurring increase in volumes in the six months ended June 30, 2015 from a refinery turn-around in our area of operations during that period .

Revenues. Revenues increased to $14.5 million for the six months ended June 30, 2016 from $10.2 million for the six months ended June 30, 2015. The increase was primarily due to an increase in refined products sales revenue of $3.9 million related to the addition of butane blending capabilities at our North Little Rock Terminal since the second quarter of 2015.

Cost of Sales, excluding depreciation and amortization. Cost of sales, excluding depreciation and amortization, increased to $6.1 million for the six months ended June 30, 2016 from $3.2 million for the six months ended June 30, 2015. The increase was primarily due to an increase in refined products sales volumes.

Operating expenses. Operating expenses decreased to $1.2 million for the six months ended June 30, 2016 from $1.4 million for the six months ended June 30, 2015. The decrease was primarily due to $0.2 million in expenses incurred in the six months ended June 30, 2015 related to inadvertent product releases.

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NGL Distribution and Sales


	Six months ended June 30,
	2016		2015		Variance
	(in thousands, unless otherwise noted)
Volumes:
NGL and refined product sales (Mgal/d) (1)		201		227		(26)
Revenues:
Gathering, transportation and storage fees	$	1,886	$	3,267	$	(1,381)
NGL and refined product sales		71,272		88,395		(17,123)
Other revenues		6,196		5,889		307
Total Revenues		79,354		97,551		(18,197)
Cost of sales, excluding depreciation and amortization (2)		(28,734)		(47,028)		18,294
Adjusted gross margin		50,620		50,523		97
Operating expenses (2)		(27,280)		(27,008)		(272)
General and administrative (2)		(4,768)		(6,740)		1,972
Other income, net		86		77		9
Segment Adjusted EBITDA	$	18,658	$	16,852	$	1,806

(1)

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

(2)

(3)

Adjusted gross margin. Adjusted gross margin remained relatively flat in the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The increase in NGL and refined product sales margin was offset by a decrease in NGL and refined product sales volume. The average NGL and refined products sales margin increased due to more favorable market conditions in the six months ended June 30, 2016 compared to the six months ended June 30, 2015 . The reduction in NGL and refined product sales volumes was primarily due to warmer than normal temperatures sustained in the six months ended June 30, 2016 partially offset by an increase in volumes due to the acquisition of Southern Propane in May 2015 .

General and administrative. General and administrative expenses decreased to $4.8 million for the six months ended June 30, 2016 from $6.7 million for the six months ended June 30, 2015 due to overall cost reduction efforts. The decrease is primarily due to a reduction in bad debt expense of $0.7 million from an improvement in collection efforts and lower personnel costs of $0.7 million related to a reduction in headcount.

Liquidity and Capital Resources

We principally require liquidity to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay distributions. 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 less likely without 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 $12.1 million per quarter, or $48.4 million per year, calculated based on the number of common and subordinated units outstanding as of August 5, 2016 and estimated unvested phantom units under our long-term incentive

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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 potential corporate overhead support from our general partner. A distribution of $0.3250 per common unit and subordinated unit for the three months ended June 30, 2016 was declared on July 25, 2016 and will be paid on August 12, 2016 to unitholders of record as of August 5, 2016.

Revolving Credit Facility

Our revolving credit facility has a maturity date of February 12, 2019 and consists of a $275.0 million revolving line of credit, which includes a sub-limit of up to $100.0 million for letters of credit, and contains an accordion feature that will allow us to increase the borrowing capacity thereunder from $275.0 million to $425.0 million, subject to obtaining additional or increased lender commitments. Our revolving credit facility is available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and for general partnership purposes, including distributions, not in contravention of law or the loan documents. Substantially all of our assets, but excluding equity in and assets of unrestricted subsidiaries and other customary exclusions, are pledged as collateral under our revolving credit facility. Our revolving credit facility contains customary covenants, including, among others, those that restrict our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on our assets. Our revolving credit facility also requires compliance with certain financial covenants, which include the following:

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

 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 of not less than $25.0 million .

We were in compliance with all covenants as of June 30, 2016.

As of August 1, 2016, we had $155.0 million of outstanding borrowings under our revolving credit facility and a remaining borrowing capacity of $105.2 million thereunder. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $14.8 million as of August 1, 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 June 30, 2016, 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.

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Cash Flow

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


	Six Months Ended June 30,
	2016		2015
	(in thousands)
Operating activities	$	30,984	$	19,322
Investing activities		(3,119)		(43,711)
Financing activities		(28,565)		23,485

Cash provided by operating activities. Cash provided by operating activities was $31.0 million for the six months ended June 30, 2016 compared to $19.3 million for the six months ended June 30, 2015. The $11.7 million increase was primarily due to a $8.2 million reduction in cash payments for commodity derivatives settled, primarily related to our propane financial swap contracts and a $0.9 million increase from the timing of collections and payments and cash used for inventory purchases.

Cash used in investing activities. Cash used in investing activities was $3.1 million for the six months ended June 30, 2016 compared to $43.7 million for the six months ended June 30, 2015. The $40.6 million decrease was primarily due to a decrease in capital expenditures of $17.9 million and an increase of $10.3 million in proceeds from the sale of assets, which includes the sale of our trucking and marketing assets in the Mid-Continent Business. The six months ended June 30, 2015 also included $12.5 million in cash used for the acquisition of Southern Propane.

Cash (used in) provided by financing activities. Cash used in financing activities was $28.6 million for the six months ended June 30, 2016 compared to cash provided by financing activities of $23.5 million for the six months ended June 30, 2015. The $52.1 million change was primarily due to a reduction in net borrowings under our revolving credit facility of $51.0 million and an increase in distributions paid to unitholders of $1.0 million for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

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

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

For the six months ended June 30, 2016, we spent $14.4 million on capital expenditures, of which $1.4 million represents maintenance capital expenditures and $13.0 million represents growth capital expenditures. We have budgeted

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$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.

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 $8.9 million and $16.7 million as of June 30, 2016 and December 31, 2015, respectively .

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2015 Form 10-K for the year ended December 31, 2015 and have not changed .

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Commodity price risk. Market risk is the risk of loss arising from adverse changes in market rates and prices. We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices. See note 7 to our condensed consolidated financial statements included in Part I, Item I of this Form 10-Q 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

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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.

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)
Swaps:
Propane (Gallons)		July 2016 - Dec 2017		4,440,589	$	305	$	237
Crude Oil (Barrels)		July 2016 - Nov 2016		(90,000)		(890)		441

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.

Interest rate risk. Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable interest rates. As of June 30, 2016, $100.0 million of our outstanding debt is economically hedged. Based on our unhedged interest rate exposure to variable rate debt outstanding as of June 30, 2016, a 1% increase or decrease in interest rates would change annual interest expense by approximately $0.6 million.

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

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

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are 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 Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures .

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Changes in Internal Controls 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 last fiscal quarter that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors under Item 1A of our annual report on Form 10-K for the year ended December 31, 2015. There has been no material change in our risk factors from those described in our 2015 Form 10-K. Such risks are not the only risks we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also have a material adverse effect on our business or our operations .

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

The following table summarizes our repurchases of equity securities during the three months ended June 30, 2016:


Period	Total number of units withheld (1)		Average price per unit		Total number of units purchased as part of publicly announced plans		Maximum number of units that may yet be purchased under the plan
April 1, 2016 - April 30, 2016		29,081	$	5.37		—		—
May 1, 2016 - May 31, 2016		793		7.47		—		—
June 1, 2016 - June 30, 2016		—		—		—		—

(1)

Represents units withheld to satisfy employees’ tax withholding obligations in connection with vesting of phantom units and restricted common and subordinated units during the period.

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Item 6. 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).

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

*Previously filed

**Filed herewith

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SIGNATURES

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


	JP ENERGY PARTNERS LP

	By:	JP ENERGY GP II LLC,
		its general partner

Date: August 8, 2016	By:	/s/ J. Patrick Barley
		J. Patrick Barley
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: August 8, 2016	By:	/s/ Patrick J. Welch
		Patrick J. Welch
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)