NGL 10-Q Quarterly Report Sept. 30, 2015

NGL ENERGY PARTNERS LP

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10-Q 1 a15-18080_110q.htm 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

(Mark One)

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

For the quarterly period ended September 30, 2015

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

For the transition period from to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware		27-3427920
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

6120 South Yale Avenue Suite 805 Tulsa, Oklahoma		74136
(Address of Principal Executive Offices)		(Zip code)

(918) 481–1119

(Registrant’s Telephone Number, Including Area Code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark 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 x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

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

At November 2, 2015, there were 106,936,303 common units issued and outstanding.

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PART I

Item 1.	Financial Statements (Unaudited)	3

	Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015	3

	Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014	4

	Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014	5

	Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015	6

	Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	100

Item 4.	Controls and Procedures	101

PART II

Item 1.	Legal Proceedings	102

Item 1A.	Risk Factors	102

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	102

Item 3.	Defaults Upon Senior Securities	102

Item 4.	Mine Safety Disclosures	102

Item 5.	Other Information	102

Item 6.	Exhibits	103

Signatures		104

Index to Exhibits		105

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Forward-Looking Statements

This Quarterly Report on Form 10—Q (“Quarterly Report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Certain words in this Quarterly Report such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key risk factors that may impact our consolidated financial position and results of operations are:

· the prices of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· energy prices generally;

· the general level of crude oil, natural gas, and natural gas liquids production;

· the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· the level of crude oil and natural gas drilling and production in producing areas in which we have water treatment and disposal facilities;

· the prices of propane and distillates relative to the prices of alternative and competing fuels;

· the price of gasoline relative to the price of corn, which impacts the price of ethanol;

· the ability to obtain adequate supplies of products in the event of an interruption in supply or transportation and the availability of capacity to transport products to market areas;

· actions taken by foreign oil and gas producing nations;

· the political and economic stability of foreign oil and gas producing nations;

· the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· the effect of natural disasters, lightning strikes, or other significant weather events;

· the availability of local, intrastate and interstate transportation infrastructure, including with respect to our truck, railcar, and barge transportation services;

· the availability, price, and marketing of competing fuels;

· the impact of energy conservation efforts on product demand;

· energy efficiencies and technological trends;

· governmental regulation and taxation;

· the impact of legislative and regulatory actions on hydraulic fracturing and on the treatment of flowback and produced water;

· hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;

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· the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;

· loss of key personnel;

· the ability to hire drivers;

· the ability to renew contracts with key customers;

· the ability to maintain or increase the margins we realize for our terminal, barging, trucking, water disposal, recycling, and discharge services;

· the ability to renew leases for our leased equipment and storage facilities;

· the nonpayment or nonperformance by our counterparties;

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

· a deterioration of the credit and capital markets;

· the ability to successfully identify and consummate strategic acquisitions, and integrate acquired assets and businesses;

· changes in the volume of hydrocarbons recovered during the wastewater treatment process;

· changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;

· changes in applicable laws and regulations, including tax, environmental, transportation and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on our business operations;

· the costs and effects of legal and administrative proceedings;

· any reduction or the elimination of the federal Renewable Fuel Standard; and

· changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Quarterly Report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under Part I, Item 1A—“Risk Factors” in our Annual Report on Form 10—K for the fiscal year ended March 31, 2015.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(U.S. Dollars in Thousands, except unit amounts)

	September 30,			March 31,
	2015			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	30,053		$	41,303
Accounts receivable–trade, net of allowance for doubtful accounts of $5,995 and $4,367, respectively	712,025			1,024,226
Accounts receivable–affiliates	6,345			17,198
Inventories	408,374			441,762
Prepaid expenses and other current assets	120,122			120,855
Total current assets	1,276,919			1,645,344

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $270,332 and $202,959, respectively	1,845,112			1,617,389
GOODWILL	1,490,928			1,402,761
INTANGIBLE ASSETS, net of accumulated amortization of $274,823 and $220,517, respectively	1,231,192			1,288,343
INVESTMENTS IN UNCONSOLIDATED ENTITIES	473,239			472,673
LOAN RECEIVABLE–AFFILIATE	23,775			8,154
OTHER NONCURRENT ASSETS	108,672			112,837
Total assets	$	6,449,837		$	6,547,501

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable–trade	$	568,523		$	833,380
Accounts payable–affiliates	18,794			25,794
Accrued expenses and other payables	164,433			195,116
Advance payments received from customers	96,380			54,234
Current maturities of long-term debt	4,040			4,472
Total current liabilities	852,170			1,112,996

LONG-TERM DEBT, net of current maturities	3,093,694			2,745,299
OTHER NONCURRENT LIABILITIES	17,679			16,086

COMMITMENTS AND CONTINGENCIES (NOTE 10)

EQUITY:
General partner, representing a 0.1% interest, 105,269 and 103,899 notional units, respectively	(34,380		)	(37,021		)
Limited partners, representing a 99.9% interest, 105,164,071 and 103,794,870 common units issued and outstanding, respectively	1,976,663			2,162,924
Accumulated other comprehensive loss	(136		)	(109		)
Noncontrolling interests	544,147			547,326
Total equity	2,486,294			2,673,120
Total liabilities and equity	$	6,449,837		$	6,547,501

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(U.S. Dollars in Thousands, except unit and per unit amounts)

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
REVENUES:
Crude oil logistics	$	1,007,578		$	2,111,143		$	2,335,362		$	4,040,426
Water solutions	47,494			52,719			101,787			100,033
Liquids	258,992			539,753			507,977			1,014,910
Retail propane	53,206			68,358			117,653			146,260
Refined products and renewables	1,825,925			2,607,220			3,668,885			3,724,717
Other	—			1,333			—			2,794
Total Revenues	3,193,195			5,380,526			6,731,664			9,029,140

COST OF SALES:
Crude oil logistics	982,719			2,083,712			2,274,711			3,981,351
Water solutions	(8,567		)	(9,439		)	(4,960		)	1,134
Liquids	221,115			514,064			453,391			976,080
Retail propane	20,879			39,894			50,443			87,418
Refined products and renewables	1,789,680			2,550,851			3,554,792			3,665,164
Other	—			383			—			2,371
Total Cost of Sales	3,005,826			5,179,465			6,328,377			8,713,518

OPERATING COSTS AND EXPENSES:
Operating	99,773			97,419			207,687			164,855
General and administrative	29,298			41,639			91,779			69,512
Depreciation and amortization	56,761			50,099			116,592			89,474
Loss on disposal or impairment of assets, net	1,291			4,134			1,712			4,566
Operating Income (Loss)	246			7,770			(14,483		)	(12,785		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	2,432			3,697			11,150			6,262
Interest expense	(31,571		)	(28,651		)	(62,373		)	(49,145		)
Other income (expense), net	1,955			(617		)	780			(1,008		)
Loss Before Income Taxes	(26,938		)	(17,801		)	(64,926		)	(56,676		)

INCOME TAX BENEFIT	2,786			1,922			2,248			887

Net Loss	(24,152		)	(15,879		)	(62,678		)	(55,789		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER	(16,166		)	(11,056		)	(31,525		)	(20,437		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(2,891		)	(3,345		)	(6,766		)	(3,410		)

NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(43,209	)	$	(30,280	)	$	(100,969	)	$	(79,636	)

BASIC AND DILUTED LOSS PER COMMON UNIT	$	(0.41	)	$	(0.34	)	$	(0.97	)	$	(0.93	)

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	105,189,463			88,331,653			104,542,427			81,267,742

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Loss

(U.S. Dollars in Thousands)

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014

Net loss	$	(24,152	)	$	(15,879	)	$	(62,678	)	$	(55,789	)
Other comprehensive income (loss)	(19		)	(22		)	(27		)	163
Comprehensive loss	$	(24,171	)	$	(15,901	)	$	(62,705	)	$	(55,626	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Six Months Ended September 30, 2015

(U.S. Dollars in Thousands, except unit amounts)

									Accumulated
				Limited Partners					Other
	General			Common					Comprehensive			Noncontrolling			Total
	Partner			Units		Amount			Loss			Interests			Equity
BALANCES AT MARCH 31, 2015	$	(37,021	)	103,794,870		$	2,162,924		$	(109	)	$	547,326		$	2,673,120
Distributions	(28,929		)	—		(125,895		)	—			(17,780		)	(172,604		)
Contributions	45			—		—			—			6,613			6,658
Business combinations	—			386,383		11,367			—			—			11,367
Equity issued pursuant to incentive compensation plan	—			1,140,444		32,919			—			—			32,919
Common unit repurchases	—			(157,626	)	(3,650		)	—			—			(3,650		)
Net income (loss)	31,525			—		(100,969		)	—			6,766			(62,678		)
Other comprehensive loss	—			—		—			(27		)	—			(27		)
TLP equity-based compensation	—			—		—			—			1,301			1,301
Other	—			—		(33		)	—			(79		)	(112		)
BALANCES AT SEPTEMBER 30, 2015	$	(34,380	)	105,164,071		$	1,976,663		$	(136	)	$	544,147		$	2,486,294

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30,
	2015			2014
OPERATING ACTIVITIES:
Net loss	$	(62,678	)	$	(55,789	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization, including amortization of debt issuance costs	124,551			97,624
Non-cash equity-based compensation expense	51,482			11,758
Loss on disposal or impairment of assets, net	1,712			4,566
Provision for doubtful accounts	3,046			1,347
Net commodity derivative gain	(44,534		)	(38,496		)
Equity in earnings of unconsolidated entities	(11,150		)	(6,262		)
Distributions of earnings from unconsolidated entities	11,593			5,180
Other	(8		)	(837		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable–trade	311,377			(358,497		)
Accounts receivable–affiliates	10,853			(33,733		)
Inventories	34,333			(203,965		)
Prepaid expenses and other assets	(7,322		)	(56,109		)
Accounts payable–trade	(265,322		)	463,767
Accounts payable–affiliates	(7,000		)	8,392
Accrued expenses and other liabilities	(17,083		)	25,719
Advance payments received from customers	40,245			73,700
Net cash provided by (used in) operating activities	174,095			(61,635		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(222,276		)	(82,851		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(150,546		)	(658,764		)
Cash flows from commodity derivatives	43,032			4,327
Proceeds from sales of assets	3,567			8,741
Investments in unconsolidated entities	(6,926		)	(26,390		)
Distributions of capital from unconsolidated entities	8,207			4,649
Loan for natural gas liquids facility	(3,913		)	—
Payments on loan for natural gas liquids facility	3,546			—
Loan to affiliate	(15,621		)	—
Net cash used in investing activities	(340,930		)	(750,288		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	1,354,700			1,979,500
Payments on revolving credit facilities	(1,006,600		)	(1,804,000		)
Issuance of notes	—			400,000
Payments on other long-term debt	(2,344		)	(4,175		)
Debt issuance costs	(1,380		)	(9,198		)
Contributions from general partner	45			395
Contributions from noncontrolling interest owners	6,613			—
Distributions to partners	(154,824		)	(111,008		)
Distributions to noncontrolling interest owners	(17,780		)	(8,654		)
Taxes paid on behalf of equity incentive plan participants	(19,083		)	—
Common unit repurchases	(3,650		)	—
Proceeds from sale of common units, net of offering costs	—			370,446
Other	(112		)	—
Net cash provided by financing activities	155,585			813,306
Net increase (decrease) in cash and cash equivalents	(11,250		)	1,383
Cash and cash equivalents, beginning of period	41,303			10,440
Cash and cash equivalents, end of period	$	30,053		$	11,823

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Note 1—Organization and Operations

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2015, our operations include:

· Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

· Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids, as well as truck and frac tank washouts.

· Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.

· Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.

· Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling, storage, and transportation operations.

Note 2—Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation. Investments we cannot exercise control of, but can exercise significant influence over, are accounted for using the equity method of accounting.

Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission. Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2015 is derived from our audited consolidated financial statements for the fiscal year ended March 31, 2015 included in our Annual Report on Form 10–K (“Annual Report”).

We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows.

These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report. Due to the seasonal nature of certain of our operations and other factors, the results of operations for interim periods are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amount of assets and liabilities reported at the date of the consolidated financial statements and the amount of revenues and expenses reported during the periods presented.

Critical estimates we make in the preparation of our condensed consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations, the collectability of accounts receivable, the recoverability of inventories, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the impairment of goodwill, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included in our Annual Report.

Fair Value Measurements

We record our commodity derivative instruments and assets and liabilities acquired in business combinations at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability. We use the following fair value hierarchy, which prioritizes valuation technique inputs used to measure fair value into three broad levels:

· Level 1—Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

· Level 2—Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

· Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to a fair value measurement requires judgment, considering factors specific to the asset or liability.

Revenue Recognition

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Several of our terminaling service agreements with throughput customers allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues during the three months and six months ended September 30, 2015 include $1.5 million and $2.9 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	26,323	$	10,445	$	57,495	$	36,429
Income taxes paid	$	533	$	1,241	$	4,616	$	2,246

Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in our condensed consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in operating activities.

Inventories

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the reporting period. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale liquids business to our retail propane business to sell the inventory in retail markets.

Inventories consist of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Crude oil	$	84,672	$	145,412
Natural gas liquids–
Propane	65,124		44,535
Butane	22,715		8,668
Other	7,028		3,874
Refined products–
Gasoline	99,208		128,092
Diesel	97,016		59,097
Renewables	22,484		44,668
Other	10,127		7,416
Total	$	408,374	$	441,762

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Investments in Unconsolidated Entities

We own noncontrolling interests in certain entities. The largest of these investments are in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, and Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), which owns a refined products storage facility.

We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee.

Our investments in unconsolidated entities consist of the following at the dates indicated:

		Ownership		Date Acquired	September 30,		March 31,
Entity	Segment	Interest		or Formed	2015		2015
					(in thousands)
Glass Mountain (1)	Crude oil logistics	50.0	%	December 2013	$	183,888	$	187,590
BOSTCO (2)	Refined products and renewables	42.5	%	July 2014	238,687		238,146
Frontera (2)	Refined products and renewables	50.0	%	July 2014	17,069		16,927
Water supply company	Water solutions	35.0	%	June 2014	16,483		16,471
Water treatment and disposal facility	Water solutions	50.0	%	August 2015	2,290		—
Ethanol production facility	Refined products and renewables	19.0	%	December 2013	14,231		13,539
Retail propane company	Retail propane	50.0	%	April 2015	591		—
Total					$	473,239	$	472,673

(1) When we acquired Gavilon, LLC, we recorded the investment in Glass Mountain at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $75.7 million at September 30, 2015. This difference relates primarily to goodwill and customer relationships.

(2) When we acquired TransMontaigne Inc. (“TransMontaigne”), we recorded the investments in BOSTCO and Frontera Brownsville LLC (“Frontera”) at fair value. On a combined basis, our investments in BOSTCO and Frontera exceed our proportionate share of the historical net book value of BOSTCO’s and Frontera’s net assets by $15.4 million at September 30, 2015. This difference relates primarily to goodwill.

Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Loan receivable (1)	$	54,413	$	58,050
Linefill (2)	35,060		35,060
Other	19,199		19,727
Total	$	108,672	$	112,837

(1) Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility being used by a third party.

(2) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2015, linefill consisted of 487,104 barrels of crude oil.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Accrued compensation and benefits	$	40,339	$	52,078
Excise and other tax liabilities	39,941		43,847
Derivative liabilities	13,729		27,950
Accrued interest	22,369		23,065
Product exchange liabilities	25,441		15,480
Other	22,614		32,696
Total	$	164,433	$	195,116

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our condensed consolidated financial statements reflects the other owners’ interests in these entities.

As part of our acquisition of TransMontaigne on July 1, 2014, we acquired a 19.7% limited partner interest in TLP. We attribute net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as including certain adjustments related to our acquisition accounting. Earnings allocable to TLP’s limited partners are net of the earnings allocable to TLP’s general partner interest. The earnings allocable to TLP’s general partner interest include the distributions of cash attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s proportionate share of undistributed earnings. Undistributed earnings are allocated to TLP’s limited partners and TLP’s general partner interest based on their respective sharing of earnings or losses specified in TLP’s partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively.

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain acquisitions are still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015–11, “Simplifying the Measurement of Inventory.” ASU No. 2015–11 requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our current accounting policies.

In April 2015, the FASB issued ASU No. 2015–03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015–03 requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At September 30, 2015, intangible assets on our condensed consolidated balance sheet include $16.1 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015–03, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015–03, will be reclassified as a reduction to long-term debt.

In May 2014, the FASB issued ASU No. 2014–09, “Revenue from Contracts with Customers.” ASU No. 2014–09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2018, and allows for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

Note 3—Loss Per Common Unit

Our loss per common unit is as follows for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except unit and per unit amounts)
Net loss attributable to parent equity	$	(27,043	)	$	(19,224	)	$	(69,444	)	$	(59,199	)
Less: Net income allocated to general partner (1)	(16,166		)	(11,056		)	(31,525		)	(20,437		)
Less: Net loss allocated to subordinated unitholders (2)	—			—			—			4,013
Net loss allocated to common unitholders	$	(43,209	)	$	(30,280	)	$	(100,969	)	$	(75,623	)

Basic and diluted weighted average common units outstanding	105,189,463			88,331,653			104,542,427			81,267,742

Basic and diluted loss per common unit	$	(0.41	)	$	(0.34	)	$	(0.97	)	$	(0.93	)

(1) Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 11.

(2) All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated after June 30, 2014, we did not allocate any income or loss after that date to the subordinated unitholders. During the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $(0.68).

The restricted units described in Note 11 were antidilutive during the three months and six months ended September 30, 2015 and 2014, but could have an impact on earnings per unit in future periods.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Note 4—Acquisitions

Year Ending March 31, 2016

Delaware Basin Water Solutions Facilities

On August 24, 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas for $50.0 million of cash. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	$	18,650
Land	400
Goodwill	12,776
Intangible asset:
Customer relationships (6 years)	16,000
Investments in unconsolidated entities	2,290
Accrued expenses and other payables	(116		)
Fair value of net assets acquired	$	50,000

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired business and the Partnership and the opportunity to use the acquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Water Solutions Facilities

As described below, we are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the six months ended September 30, 2015, we purchased eight water treatment and disposal facilities under these development agreements. On a combined basis, we paid $82.6 million of cash and issued 386,383 common units, valued at $11.4 million, in exchange for these facilities.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	$	32,449
Buildings and leasehold improvements (7–30 years)	7,281
Land	1,028
Other (5 years)	30
Goodwill	55,529
Accrued expenses and other payables	(2,102		)
Other noncurrent liabilities	(233		)
Fair value of net assets acquired	$	93,982

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Retail Propane Businesses

During the six months ended September 30, 2015, we acquired four retail propane businesses and paid $15.9 million of cash on a combined basis in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016.

Year Ended March 31, 2015

As described in Note 2, pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. The changes we made during the six months ended September 30, 2015 to the estimated acquisition date fair values of assets acquired and liabilities assumed in these business combinations are described below. We have not retrospectively adjusted previously issued financial statements for these changes, as we do not believe the changes are material.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Natural Gas Liquids Storage Facility

In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6 million of cash, net of cash acquired, and issued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. The agreement for this acquisition contemplates post-closing payments for certain working capital items. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2015. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed:

	Estimated At
	September 30,			March 31,
	2015			2015			Change
	(in thousands)
Accounts receivable–trade	$	42		$	42		$	—
Prepaid expenses and other current assets	843			600			243
Property, plant and equipment:
Natural gas liquids terminal and storage assets (2–30 years)	62,205			62,205			—
Vehicles and railcars (3–25 years)	75			75			—
Land	68			68			—
Other	32			32			—
Construction in progress	19,525			19,525			—
Goodwill	168,310			151,853			16,457
Intangible assets:
Customer relationships (15 years)	76,000			85,000			(9,000		)
Non-compete agreements (10 years)	4,300			12,000			(7,700		)
Accounts payable–trade	(931		)	(931		)	—
Accrued expenses and other payables	(6,511		)	(6,511		)	—
Advance payments received from customers	(1,015		)	(1,015		)	—
Other noncurrent liabilities	(6,817		)	(6,817		)	—
Fair value of net assets acquired	$	316,126		$	316,126		$	—

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired business and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain storage leases were at unfavorable terms relative to acquisition-date market conditions, we recorded a liability of $12.8 million related to these leases in the acquisition accounting, a portion of which we recorded to accrued expenses and other payables and a portion of which we recorded to other noncurrent liabilities. We amortized $2.9 million of this balance as an increase to revenues during the six months ended September 30, 2015. We will amortize the remainder of this liability over the terms of the leases. The following table summarizes the future amortization of this liability (in thousands):

Year Ending March 31,
2016 (six months)	$	2,903
2017	4,905
2018	1,306
2019	88

Bakken Water Solutions Facilities

On November 21, 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 million of cash. During the six months ended September 30, 2015, we completed the acquisition accounting for these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Property, plant and equipment:
Vehicles (10 years)	$	63		$	63		$	—
Water treatment facilities and equipment (3—30 years)	5,815			5,815			—
Buildings and leasehold improvements (7—30 years)	130			130			—
Land	100			100			—
Goodwill	4,421			6,560			(2,139		)
Intangible asset:
Customer relationships (7 years)	24,300			22,000			2,300
Other noncurrent assets	75			—			75
Other noncurrent liabilities	(304		)	(68		)	(236		)
Fair value of net assets acquired	$	34,600		$	34,600		$	—

TransMontaigne Inc.

On July 1, 2014, we acquired TransMontaigne for $200.3 million of cash, net of cash acquired (including $174.1 million paid at closing and $26.2 million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, a 19.7%

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

During the three months ended June 30, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Cash and cash equivalents	$	1,469		$	1,469		$	—
Accounts receivable–trade	199,366			197,829			1,537
Accounts receivable–affiliates	528			528			—
Inventories	373,870			373,870			—
Prepaid expenses and other current assets	15,110			15,001			109
Property, plant and equipment:
Refined products terminal assets and equipment (20 years)	415,317			399,323			15,994
Vehicles	1,696			1,698			(2		)
Crude oil tanks and related equipment (20 years)	1,085			1,058			27
Information technology equipment	7,253			7,253			—
Buildings and leasehold improvements (20 years)	15,323			14,770			553
Land	61,329			70,529			(9,200		)
Tank bottoms (indefinite life)	46,900			46,900			—
Other	15,536			15,534			2
Construction in progress	4,487			4,487			—
Goodwill	30,169			28,074			2,095
Intangible assets:
Customer relationships (15 years)	66,000			76,100			(10,100		)
Pipeline capacity rights (30 years)	87,618			87,618			—
Investments in unconsolidated entities	240,583			240,583			—
Other noncurrent assets	3,911			3,911			—
Accounts payable–trade	(113,103		)	(113,066		)	(37		)
Accounts payable–affiliates	(69		)	(69		)	—
Accrued expenses and other payables	(79,405		)	(78,427		)	(978		)
Advance payments received from customers	(1,919		)	(1,919		)	—
Long-term debt	(234,000		)	(234,000		)	—
Other noncurrent liabilities	(33,227		)	(33,227		)	—
Noncontrolling interests	(545,120		)	(545,120		)	—
Fair value of net assets acquired	$	580,707		$	580,707		$	—

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired business and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of this pipeline exceeds the pipeline’s capacity, and the limited capacity is allocated based on a shipper’s historical shipment volumes.

The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP’s common units on the acquisition date by the number of TLP common units held by parties other than us, adjusted for a lack-of-control discount.

Water Solutions Facilities

As described above, we are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under these development agreements. We also purchased a 75% interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $190.0 million of cash and issued 1,322,032 common units, valued at $37.8 million, in exchange for these 17 facilities.

During the six months ended September 30, 2015, we completed the acquisition accounting for 12 of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Accounts receivable–trade	$	939		$	939		$	—
Inventories	253			253			—
Prepaid expenses and other current assets	62			62			—
Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	60,784			60,784			—
Buildings and leasehold improvements (7–30 years)	5,701			5,701			—
Land	2,122			2,122			—
Other (5 years)	101			101			—
Goodwill	93,358			93,358			—
Intangible asset:							—
Customer relationships (4 years)	10,000			10,000			—
Other noncurrent assets	50			50			—
Accounts payable–trade	(58		)	(58		)	—
Accrued expenses and other payables	(1,092		)	(1,092		)	—
Other noncurrent liabilities	(420		)	(420		)	—
Noncontrolling interest	(5,775		)	(5,775		)	—
Fair value of net assets acquired	$	166,025		$	166,025		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other five water treatment and disposal facilities, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2015. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed:

	Estimated At
	September 30,			March 31,
	2015			2015			Change
	(in thousands)
Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	$	19,198		$	18,922		$	276
Buildings and leasehold improvements (7–30 years)	4,989			4,549			440
Land	1,005			987			18
Other (5 years)	31			28			3
Goodwill	38,675			39,412			(737		)
Accrued expenses and other payables	(2,000		)	(2,000		)	—
Other noncurrent liabilities	(162		)	(162		)	—
Fair value of net assets acquired	$	61,736		61,736			$	—

Retail Propane Businesses

During the year ended March 31, 2015, we acquired eight retail propane businesses. On a combined basis, we paid $39.1 million of cash and issued 132,100 common units, valued at $3.7 million, in exchange for these assets and operations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

During the six months ended September 30, 2015, we completed the acquisition accounting for all of these business combinations. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Accounts receivable–trade	$	2,237		$	2,237		$	—
Inventories	771			771			—
Prepaid expenses and other current assets	110			110			—
Property, plant and equipment:
Retail propane equipment (15–20 years)	13,177			13,177			—
Vehicles and railcars (5–7 years)	2,332			2,332			—
Buildings and leasehold improvements (30 years)	534			784			(250		)
Land	505			655			(150		)
Other (5–7 years)	118			116			2
Goodwill	8,097			8,097			—
Intangible assets:
Customer relationships (10–15 years)	17,563			17,563			—
Non-compete agreements (5–7 years)	500			500			—
Trade names (3–12 years)	950			950			—
Accounts payable–trade	(1,523		)	(1,921		)	398
Advance payments received from customers	(1,750		)	(1,750		)	—
Current maturities of long-term debt	(78		)	(78		)	—
Long-term debt, net of current maturities	(760		)	(760		)	—
Fair value of net assets acquired	$	42,783		$	42,783		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Note 5—Property, Plant and Equipment

Our property, plant and equipment consists of the following at the dates indicated:

	Estimated	September 30,			March 31,
Description	Useful Lives	2015			2015
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	134,335		$	132,851
Refined products terminal assets and equipment	20 years	439,154			403,609
Retail propane equipment	2–30 years	191,493			181,140
Vehicles and railcars	3–25 years	185,216			180,679
Water treatment facilities and equipment	3–30 years	405,382			317,317
Crude oil tanks and related equipment	2–40 years	113,524			109,909
Barges and towboats	5–40 years	78,718			59,848
Information technology equipment	3–7 years	39,558			34,915
Buildings and leasehold improvements	3–40 years	118,338			98,989
Land		101,245			107,098
Tank bottoms		64,741			62,656
Other	3–30 years	35,818			34,415
Construction in progress		207,922			96,922
		2,115,444			1,820,348
Accumulated depreciation		(270,332		)	(202,959		)
Net property, plant and equipment		$	1,845,112		$	1,617,389

The following table summarizes depreciation expense for the periods indicated:

Three Months Ended September 30,				Six Months Ended September 30,
2015		2014		2015		2014
(in thousands)
$	34,469	$	28,387	$	70,264	$	46,870

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. The following table summarizes the tank bottoms included in the table above at the dates indicated:

	September 30, 2015			March 31, 2015
	Volume			Volume
Product	(in barrels) (in thousands)	Value (in thousands)		(in barrels) (in thousands)	Value (in thousands)
Gasoline	219	$	25,710	219	$	25,710
Crude oil	231	19,320		184	16,835
Diesel	121	14,753		124	15,153
Renewables	41	4,220		41	4,220
Other	12	738		12	738
Total		$	64,741		$	62,656

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Note 6—Goodwill

The following table summarizes changes in goodwill by segment for the six months ended September 30, 2015:

										Refined
	Crude Oil		Water					Retail		Products and
	Logistics		Solutions			Liquids		Propane		Renewables		Total
	(in thousands)
Balances at March 31, 2015	$	579,846	$	401,656		$	234,803	$	122,382	$	64,074	$	1,402,761
Revisions to acquisition accounting (Note 4)	—		(2,876		)	16,457		—		2,095		15,676
Acquisitions (Note 4)	—		68,305			—		4,186		—		72,491
Balances at September 30, 2015	$	579,846	$	467,085		$	251,260	$	126,568	$	66,169	$	1,490,928

Note 7—Intangible Assets

Our intangible assets consist of the following at the dates indicated:

		September 30, 2015				March 31, 2015
	Estimated	Gross Carrying		Accumulated		Gross Carrying		Accumulated
Description	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable–
Customer relationships	3–20 years	$	924,467	$	199,578	$	921,418	$	159,215
Pipeline capacity rights	30 years	119,636		4,565		119,636		2,571
Water facility development agreement	5 years	14,000		6,300		14,000		4,900
Executory contracts and other agreements	2–10 years	23,920		19,768		23,920		18,387
Non-compete agreements	2–10 years	19,388		12,169		26,662		10,408
Trade names	2–12 years	15,439		10,399		15,439		7,569
Debt issuance costs	3–10 years	56,545		22,044		55,165		17,467
Total amortizable		1,173,395		274,823		1,176,240		220,517
Non-amortizable–
Customer commitments		310,000		—		310,000		—
Trade names		22,620		—		22,620		—
Total non-amortizable		332,620		—		332,620		—

Total		$	1,506,015	$	274,823	$	1,508,860	$	220,517

The weighted-average remaining amortization period for intangible assets is approximately 11 years.

Amortization expense is as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
Recorded In	2015		2014		2015		2014
	(in thousands)
Depreciation and amortization	$	22,291	$	21,711	$	46,328	$	42,604
Cost of sales	1,700		1,984		3,401		4,121
Interest expense	2,276		2,117		4,558		4,029
Total	$	26,267	$	25,812	$	54,287	$	50,754

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Expected amortization of our intangible assets, exclusive of assets that are not yet amortizable, is as follows (in thousands):

Year Ending March 31,
2016 (six months)	$	54,702
2017	104,446
2018	100,474
2019	90,926
2020	84,159
Thereafter	463,865
Total	$	898,572

Note 8—Long-Term Debt

Our long-term debt consists of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Revolving credit facility–
Expansion capital borrowings	$	1,083,000	$	702,500
Working capital borrowings	656,000		688,000
5.125% Notes due 2019	400,000		400,000
6.875% Notes due 2021	450,000		450,000
6.650% Notes due 2022	250,000		250,000
TLP credit facility	249,600		250,000
Other long-term debt	9,134		9,271
	3,097,734		2,749,771
Less: Current maturities	4,040		4,472
Long-term debt	$	3,093,694	$	2,745,299

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2015, our Revolving Credit Facility had a total capacity of $2.296 billion.

The Expansion Capital Facility had a total capacity of $1.258 billion for cash borrowings at September 30, 2015. At that date, we had outstanding borrowings of $1.083 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at September 30, 2015. At that date, we had outstanding borrowings of $656.0 million and outstanding letters of credit of $89.6 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. During October 2015, we entered into an agreement with the lenders to increase the total capacity on the Expansion Capital Facility by $150 million.

The commitments under the Credit Agreement mature on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50% to 1.50% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2015, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2015 of 2.21%, calculated as the LIBOR rate of 0.21% plus a margin of 2.0%. At September 30, 2015, the interest rate in effect on letters of credit was 2.25%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity.

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At September 30, 2015, our leverage ratio was approximately 3.5 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2015, our interest coverage ratio was approximately 5.9 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2015, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate, merge, or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) failure to pay principal or interest when due, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness before maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes may declare all of the 2022 Notes to be due and payable immediately.

At September 30, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

TLP is party to a credit agreement with a syndicate of banks that provides for a revolving credit facility (the “TLP Credit Facility”). The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million or (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility). The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of TLP’s “available cash” as defined in TLP’s partnership agreement. TLP may make acquisitions and investments that meet the definition of “permitted acquisitions,” “other investments” which may not exceed 5% of “consolidated net tangible assets,” and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The commitments under the TLP Credit Facility mature on July 31, 2018.

TLP may elect to have loans under the TLP Credit Facility bear interest at either (i) a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays commitment fees on any unused capacity, ranging from 0.375% to 0.5% per year, depending on the total leverage ratio then in effect. For the three months ended September 30, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.6%. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP’s assets, including TLP’s investments in unconsolidated entities. At September 30, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $249.6 million and no outstanding letters of credit.

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) if TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on “Consolidated EBITDA” as defined in the TLP Credit Facility. The TLP Credit Facility is non-recourse to the Partnership. At September 30, 2015, TLP was in compliance with the covenants under the TLP Credit Facility.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2015, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

Cash and cash equivalents	$	791
Accounts receivable–trade	3,074
Accounts receivable–affiliates	679
Inventories	1,250
Prepaid expenses and other current assets	858
Property, plant and equipment, net	477,357
Goodwill	30,169
Intangible assets, net	61,696
Investments in unconsolidated entities	255,757
Other noncurrent assets	968
Accounts payable–trade	(6,760		)
Accounts payable–affiliates	(121		)
Net intercompany payable	(1,911		)
Accrued expenses and other payables	(7,054		)
Advanced payments received from customers	(151		)
Long-term debt	(249,600		)
Other noncurrent liabilities	(3,441		)
Net assets	$	563,561

Other Long-Term Debt

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at September 30, 2015:

	Revolving								TLP		Other
	Credit		2019		2021		2022		Credit		Long-Term
Year Ending March 31,	Facility		Notes		Notes		Notes		Facility		Debt		Total
	(in thousands)
2016 (six months)	$	—	$	—	$	—	$	—	$	—	$	1,891	$	1,891
2017	—		—		—		—		—		2,879		2,879
2018	—		—		—		25,000		—		2,129		27,129
2019	1,739,000		—		—		50,000		249,600		1,413		2,040,013
2020	—		400,000		—		50,000		—		344		450,344
Thereafter	—		—		450,000		125,000		—		478		575,478
Total	$	1,739,000	$	400,000	$	450,000	$	250,000	$	249,600	$	9,134	$	3,097,734

Note 9—Income Taxes

We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her proportionate share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our initial public offering.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our condensed consolidated financial statements at September 30, 2015 or March 31, 2015.

Note 10—Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

Our condensed consolidated balance sheet at September 30, 2015 includes a liability of $4.8 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired.

In addition to the obligations described above, we may be required to remove facilities or perform other remediation upon retirement of certain other assets. We believe the present value of these asset retirement obligations, under current laws and regulations, after considering the estimated lives of our facilities, is not material to our consolidated financial position or results of operations.

Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions about the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at September 30, 2015 (in thousands):

Year Ending March 31,
2016 (six months)	$	60,441
2017	106,125
2018	90,783
2019	66,385
2020	56,509
Thereafter	123,193
Total	$	503,436

The following table summarizes rental expense for operating leases for the periods indicated:

Three Months Ended September 30,				Six Months Ended September 30,
2015		2014		2015		2014
(in thousands)
$	33,354	$	29,333	$	67,075	$	54,633

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. The following table summarizes future minimum throughput payments under these agreements at September 30, 2015 (in thousands):

Year Ending March 31,
2016 (six months)	$	56,753
2017	85,349
2018	85,435
2019	84,643
2020	74,811
Thereafter	90,972
Total	$	477,963

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods. The following table summarizes such commitments at September 30, 2015:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	61,618	$	38,073
Natural gas liquids index-price (gallons)	526,956	264,790
Crude oil fixed-price (barrels)	13	578
Crude oil index-price (barrels)	7,982	336,151
Sale commitments:
Natural gas liquids fixed-price (gallons)	179,849	127,038
Natural gas liquids index-price (gallons)	253,827	194,588
Crude oil fixed-price (barrels)	1,018	46,279
Crude oil index-price (barrels)	7,842	391,920

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (see Note 12) or inventory positions (see Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value in our condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $21.6 million of our prepaid expenses and other current assets and $13.5 million of our accrued expenses and other payables at September 30, 2015.

Note 11—Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner is not required to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Common Units Issued in Business Combinations

During the six months ended September 30, 2015, we issued 386,383 common units as consideration for a water solutions facility acquisition. In October 2015, we issued 52,199 common units as partial consideration of the acquisition of a retail propane business.

Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our units. During September 2015, we repurchased 157,626 common units for an aggregate price of $3.7 million.

Our Distribution Policy

Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

expenses, including payments to the general partner and its affiliates, referred to as “available cash.” The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.” Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following table illustrates the percentage allocations of available cash from operating surplus between our limited partners and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our general partner and our limited partners in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our limited partners and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, and assume that our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs.

							Marginal Percentage Interest In
							Distributions
	Total Quarterly Distribution Per Unit						Limited Partners		General Partner

Minimum quarterly distribution					$	0.337500	99.9	%	0.1	%
First target distribution	above	$	0.337500	up to	$	0.388125	99.9	%	0.1	%
Second target distribution	above	$	0.388125	up to	$	0.421875	86.9	%	13.1	%
Third target distribution	above	$	0.421875	up to	$	0.506250	76.9	%	23.1	%
Thereafter	above	$	0.506250				51.9	%	48.1	%

In October 2015, we declared a distribution of $0.64 per common unit, to be paid on November 13, 2015 to unitholders of record on November 3, 2015. This distribution is expected to be $83.6 million, including amounts to be paid on common and general partner notional units as well as an incentive distribution.

TLP’s Distribution Policy

TLP’s partnership agreement requires it to pay a quarterly distribution to unitholders as of the record date to the extent TLP has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to TLP’s general partner and its affiliates, referred to as “available cash.” TLP’s general partner will also receive, in addition to distributions on its 2.0% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.” TLP’s general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in TLP’s partnership agreement.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table illustrates the percentage allocations of available cash from operating surplus between TLP’s limited partners and TLP’s general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of TLP’s general partner and TLP’s limited partners in any available cash from operating surplus TLP distributes up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus TLP distributes reaches the next target distribution level, if any. The percentage interests shown for TLP’s limited partners and TLP’s general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for TLP’s general partner include its 2.0% general partner interest, and assume that TLP’s general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its IDRs.

							Marginal Percentage Interest In
							Distributions
	Total Quarterly Distribution Per Unit						Limited Partners		General Partner
Minimum quarterly distribution					$	0.40	98	%	2	%
First target distribution	above	$	0.40	up to	$	0.44	98	%	2	%
Second target distribution	above	$	0.44	up to	$	0.50	85	%	15	%
Third target distribution	above	$	0.50	up to	$	0.60	75	%	25	%
Thereafter	above	$	0.60				50	%	50	%

In October 2015, TLP declared a distribution of $0.6650 per unit, which was paid on November 6, 2015. We received a total of $4.0 million from this distribution on our general partner interest, IDRs, and limited partner interest. The noncontrolling interest owners received a total of $8.6 million from this distribution.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based incentive compensation. Our general partner has granted certain restricted units to employees and directors, which vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions accrue to or are paid on the restricted units during the vesting period. The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

The following table summarizes the Service Award activity during the six months ended September 30, 2015:

Unvested Service Award units at March 31, 2015	2,260,400
Units granted	787,562
Units vested and issued	(820,017	)
Units withheld for employee taxes	(443,663	)
Units forfeited	(64,000	)
Unvested Service Award units at September 30, 2015	1,720,282

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes the scheduled vesting of our unvested Service Award units:

Year Ending March 31,		Number of Units
2016 (six months)		45,000
2017		820,641
2018		747,641
Thereafter		107,000
Unvested Service Award units at September 30, 2015		1,720,282

We record the expense for the first tranche of each Service Award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. The following table summarizes expense related to Service Award units for the periods indicated:

Three Months Ended September 30,				Six Months Ended September 30,
2015		2014		2015		2014
(in thousands)
$	14,859	$	13,745	$	33,362	$	21,659

Of the restricted units granted and vested during the six months ended September 30, 2015, 465,239 units were granted as a bonus for performance during the fiscal year ended March 31, 2015. We accrued expense of $10.0 million during the fiscal year ended March 31, 2015 and $3.8 million during the three months ended June 30, 2015 for estimates of the value of such bonus units that would be granted. During the three months ended September 30, 2015, we reversed $2.0 million of this expense to true-up the estimate to the $11.8 million of actual expense associated with these bonuses. Since the units were not formally granted until July 2015, the full $11.8 million value is reflected in the expense during the three months ended September 30, 2015 in the table above.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2015 (in thousands), after taking into consideration estimated forfeitures of approximately 167,000 units. For purposes of this calculation, we used the closing price of our common units on September 30, 2015, which was $19.97.

Year Ending March 31,
2016 (six months)	$	8,364
2017	13,533
2018	4,461
Thereafter	1,063
Total	$	27,421

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table is a rollforward of the liability related to the Service Award units, which is reported within accrued expenses and other payables in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2015	$	6,154
Expense recorded	33,362
Value of units vested and issued	(23,261		)
Taxes paid on behalf of participants	(12,663		)
Balance at September 30, 2015	$	3,592

The weighted-average fair value of the Service Award units at September 30, 2015 was $16.35 per common unit, which was calculated as the closing price of our common units on September 30, 2015, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

During April 2015, our general partner granted Performance Award units to certain employees. The following table summarizes the maximum number of units that could vest on these Performance Awards for each vesting tranche, taking into consideration any Performance Awards that have been forfeited since the grant date:

		Maximum Performance
Vesting Date of Tranche		Award Units
July 1, 2016		685,382
July 1, 2017		677,382
Total		1,362,764

The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. Performance will be measured over the following periods:

Vesting Date of Tranche		Performance Period for Tranche
July 1, 2016		July 1, 2013 through June 30, 2016
July 1, 2017		July 1, 2014 through June 30, 2017

The following table summarizes the percentage of the maximum Performance Award units that will vest depending on the percentage of entities in the Index that NGL outperforms:

Percentage of Entities in the		Percentage of Maximum
Index that NGL Outperforms		Performance Award Units to Vest
Less than 50%		0%
50%–75%		25%–50%
75%–90%		50%–100%
Greater than 90%		100%

The April 2015 Performance Award grants included a tranche that vested on July 1, 2015. During the July 1, 2012 through June 30, 2015 performance period, the return on our common units exceeded the return on 83% of our peer companies in the Index. As a result, the July 1, 2015 tranche of the Performance Awards vested at 76% of the maximum number of awards, and 530,564 common units vested on July 1, 2015. Of these units, recipients elected for us to withhold 210,137 common units for employee taxes, valued at $6.4 million. We issued the remaining 320,427 common units, valued at $9.7 million, on July 1, 2015.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes the estimated fair value for each unvested tranche at September 30, 2015 (without consideration of estimated forfeitures):

	Fair Value of
Vesting Date of Tranche	Unvested Awards
	(in thousands)
July 1, 2016	$	4,276
July 1, 2017	2,906
Total	$	7,182

We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation. The following table summarizes the expense recorded for each vesting tranche during the periods indicated:

	Three Months Ended
Vesting Date of Tranche	June 30, 2015		September 30, 2015			Total
	(in thousands)
July 1, 2015	$	15,469	$	609		$	16,078
July 1, 2016	1,720		(220		)	1,500
July 1, 2017	602		(60		)	542
Total	$	17,791	$	329		$	18,120

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2015 (in thousands), after taking into consideration estimated forfeitures. For purposes of this calculation, we used the September 30, 2015 fair value of the Performance Awards.

Year Ending March 31,
2016 (six months)	$	2,321
2017	2,080
2018	307
Total	$	4,708

The following table is a rollforward of the liability related to the Performance Award units, which is reported within accrued expenses and other payables in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2015	$	—
Expense recorded	18,120
Value of units vested and issued	(9,658		)
Taxes paid on behalf of participants	(6,420		)
Balance at September 30, 2015	$	2,042

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the LTIP plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2015, approximately 5.3 million common units remain available for issuance under the LTIP.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Note 12—Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current assets and liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our condensed consolidated balance sheet at the dates indicated:

	September 30, 2015						March 31, 2015
	Derivative			Derivative			Derivative			Derivative
	Assets			Liabilities			Assets			Liabilities
	(in thousands)
Level 1 measurements	$	41,612		$	(5,314	)	$	83,779		$	(3,969	)
Level 2 measurements	27,464			(15,070		)	34,963			(28,764		)
	69,076			(20,384		)	118,742			(32,733		)

Netting of counterparty contracts (1)	(3,537		)	3,537			(1,804		)	1,804
Net cash collateral provided (held)	(17,980		)	3,118			(56,660		)	2,979
Commodity derivatives in condensed consolidated balance sheet	$	47,559		$	(13,729	)	$	60,278		$	(27,950	)

(1) Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty.

The following table summarizes the accounts that include our commodity derivative assets and liabilities in our condensed consolidated balance sheets:

	September 30,			March 31,
	2015			2015
	(in thousands)
Prepaid expenses and other current assets	$	47,559		$	60,278
Accrued expenses and other payables	(13,729		)	(27,950		)
Net commodity derivative asset	$	33,830		$	32,328

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives as hedges.

		Net Long (Short)		Fair Value
		Notional		of
		Units		Net Assets
Contracts	Settlement Period	(Barrels)		(Liabilities)
		(in thousands)
At September 30, 2015–
Cross-commodity (1)	October 2015–March 2017	86		$	886
Crude oil fixed-price (2)	October 2015–December 2016	(1,540	)	3,407
Propane fixed-price (2)	October 2015–December 2017	1,005		(3,925		)
Refined products fixed-price (2)	October 2015–January 2017	(3,580	)	43,331
Other	October 2015–June 2016			4,993
				48,692
Net cash collateral held				(14,862		)
Net commodity derivatives in condensed consolidated balance sheet				$	33,830

At March 31, 2015–
Cross-commodity (1)	April 2015–March 2016	98		$	(105	)
Crude oil fixed-price (2)	April 2015–June 2015	(1,113	)	(171		)
Crude oil index-price (3)	April 2015–July 2015	751		1,835
Propane fixed-price (2)	April 2015–December 2016	193		(2,842		)
Refined products fixed-price (2)	April 2015–December 2015	(3,005	)	84,996
Other	April 2015–December 2015			2,296
				86,009
Net cash collateral held				(53,681		)
Net commodity derivatives in condensed consolidated balance sheet				$	32,328

(1) Cross-commodity—We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

(2) Commodity fixed-price—We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

(3) Commodity index-price—We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different indices. These indices may vary in the commodity grade or location, or in the timing of delivery within a given month. These contracts are derivatives we have entered into as an economic hedge against the risk of one index moving relative to another index.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes the net gains recorded from our commodity derivatives to cost of sales for the periods indicated:

Three Months Ended September 30,				Six Months Ended September 30,
2015		2014		2015		2014
(in thousands)
$	85,777	$	55,981	$	44,534	$	38,496

Credit Risk

We have credit policies with regard to our counterparties on derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At September 30, 2015, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2015, we had $1.739 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.21%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.2 million, based on borrowings outstanding at September 30, 2015.

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2015, TLP had $249.6 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.72%. A change in interest rates of 0.125% would result in an increase or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2015.

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2015 (in thousands):

5.125% Notes due 2019	$	378,000
6.875% Notes due 2021	446,625
6.650% Notes due 2022	254,175

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by other entities, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair value hierarchy.

Note 13—Segments

The following table summarizes certain financial data related to our segments. Transactions between segments are recorded based on prices negotiated between the segments.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

Our liquids and retail propane segments each consist of two divisions, which are organized based on the location of the operations. The “corporate and other” category consists primarily of certain corporate expenses that are not allocated to the reportable segments.

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Revenues(1):
Crude oil logistics–
Crude oil sales	$	997,106		$	2,109,618		$	2,309,889		$	4,038,673
Crude oil transportation and other	12,746			11,581			31,695			21,584
Water solutions–
Service fees	35,203			24,238			71,941			41,939
Recovered hydrocarbons	10,746			23,334			26,564			47,349
Water transportation	—			5,147			—			10,745
Other revenues	1,545			—			3,282			—
Liquids–
Propane sales	98,770			240,933			204,260			463,736
Other product sales	160,836			306,660			308,347			595,075
Other revenues	10,122			6,279			19,622			11,582
Retail propane–
Propane sales	36,119			48,552			79,304			100,578
Distillate sales	7,678			11,530			20,625			30,225
Other revenues	9,409			8,276			17,724			15,457
Refined products and renewables–
Refined products sales	1,704,259			2,466,389			3,413,208			3,452,612
Renewables sales	93,189			116,825			199,342			248,099
Service fees	28,739			24,006			56,812			24,006
Corporate and other	—			1,333			—			2,794
Elimination of intersegment sales	(13,272		)	(24,175		)	(30,951		)	(75,314		)
Total revenues	$	3,193,195		$	5,380,526		$	6,731,664		$	9,029,140

Depreciation and Amortization:
Crude oil logistics	$	10,053		$	9,240		$	20,055		$	18,971
Water solutions	22,416			17,573			43,262			34,665
Liquids	2,745			3,384			7,749			6,585
Retail propane	8,909			7,684			17,615			15,255
Refined products and renewables	11,152			11,917			25,327			12,761
Corporate and other	1,486			301			2,584			1,237
Total depreciation and amortization	$	56,761		$	50,099		$	116,592		$	89,474

Operating Income (Loss):
Crude oil logistics	$	(75	)	$	38		$	11,885		$	1,501
Water solutions	205			14,792			(2,867		)	13,885
Liquids	20,370			10,929			19,899			10,016
Retail propane	(1,765		)	(3,062		)	(2,465		)	(4,648		)
Refined products and renewables	(5,244		)	8,822			27,776			7,567
Corporate and other	(13,245		)	(23,749		)	(68,711		)	(41,106		)
Total operating income (loss)	$	246		$	7,770		$	(14,483	)	$	(12,785	)

(1) During the three months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes additions to property, plant and equipment by segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Three Months Ended September 30,				Six Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Additions to property, plant and equipment:
Crude oil logistics	$	44,384	$	39,464	$	107,023	$	81,413
Water solutions	56,531		40,610		117,020		48,072
Liquids	18,886		1,911		36,064		3,070
Retail propane	12,748		9,567		19,643		12,411
Refined products and renewables	7,588		512,281		23,283		512,281
Corporate and other	—		1,809		1,169		3,262
Total	$	140,137	$	605,642	$	304,202	$	660,509

The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

	September 30,		March 31,
	2015		2015
	(in thousands)
Long-lived assets, net:
Crude oil logistics	$	1,412,181	$	1,327,538
Water solutions	1,275,920		1,119,794
Liquids	559,763		534,560
Retail propane	477,391		467,652
Refined products and renewables	795,167		808,757
Corporate and other	46,810		50,192
Total	$	4,567,232	$	4,308,493

Total assets:
Crude oil logistics	$	2,088,087	$	2,337,188
Water solutions	1,375,023		1,185,929
Liquids	770,052		713,547
Retail propane	541,002		542,476
Refined products and renewables	1,549,577		1,668,836
Corporate and other	126,096		99,525
Total	$	6,449,837	$	6,547,501

Note 14—Transactions with Affiliates

SemGroup Corporation (“SemGroup”) holds ownership interests in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales, respectively, in our condensed consolidated statements of operations. We also lease crude oil storage from SemGroup.

We purchase ethanol from one of our equity method investees. These transactions are reported within cost of sales in our condensed consolidated statements of operations.

Certain members of our management and members of their families own interests in entities from which we have purchased products and services and to which we have sold products and services. During the six months ended September 30, 2015, $23.2 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

The following table summarizes these related party transactions:

	Three Months Ended September 30,				Six Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Sales to SemGroup	$	4,593	$	37,600	$	42,031	$	63,583
Purchases from SemGroup	6,478		46,564		45,303		85,684
Sales to equity method investees	1,696		9,131		3,086		9,131
Purchases from equity method investees	24,816		34,689		55,764		70,965
Sales to entities affiliated with management	91		1,706		198		1,854
Purchases from entities affiliated with management	16,214		3,845		23,394		6,984

Accounts receivable from affiliates consist of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Receivables from SemGroup	$	5,456	$	13,443
Receivables from equity method investees	679		652
Receivables from entities affiliated with management	210		3,103
Total	$	6,345	$	17,198

Accounts payable to affiliates consist of the following at the dates indicated:

	September 30,		March 31,
	2015		2015
	(in thousands)
Payables to SemGroup	$	5,912	$	11,546
Payables to equity method investees	4,741		6,788
Payables to entities affiliated with management	8,141		7,460
Total	$	18,794	$	25,794

We also have a loan receivable of $23.8 million at September 30, 2015 from one of our equity method investees. The investee is required to make monthly principal payments beginning on June 1, 2018 with the remaining principal balance due on May 31, 2020.

Note 15—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and 2021 Notes (see Note 8). Pursuant to Rule 3—10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

There are no significant restrictions that prevent the parent or any of the guarantor subsidiaries from obtaining funds from their respective subsidiaries by dividend or loan, other than restrictions contained in TLP’s Credit Facility. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

For purposes of the tables below, (i) the condensed consolidating financial information is presented on a legal entity basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to (from) consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the condensed consolidating statement of cash flow tables below.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	September 30, 2015
	NGL Energy
	Partners LP		NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23,042	$	—	$	4,547		$	2,464		$	—		$	30,053
Accounts receivable—trade, net of allowance for doubtful accounts	—		—		702,282			9,743			—			712,025
Accounts receivable—affiliates	—		—		5,666			679			—			6,345
Inventories	—		—		406,633			1,741			—			408,374
Prepaid expenses and other current assets	—		—		103,017			17,105			—			120,122
Total current assets	23,042		—		1,222,145			31,732			—			1,276,919

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,300,194			544,918			—			1,845,112
GOODWILL	—		—		1,458,567			32,361			—			1,490,928
INTANGIBLE ASSETS, net of accumulated amortization	16,090		—		1,150,618			64,484			—			1,231,192
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		217,482			255,757			—			473,239
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,465,775		—		(1,428,990		)	(36,785		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,556,474		—		77,741			—			(1,634,215		)	—
LOAN RECEIVABLE—AFFILIATE	—		—		23,775			—			—			23,775
OTHER NONCURRENT ASSETS	—		—		107,215			1,457			—			108,672
Total assets	$	3,061,381	$	—	$	4,128,747		$	893,924		$	(1,634,215	)	$	6,449,837

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—	$	559,744		$	8,779		$	—		$	568,523
Accounts payable—affiliates	1		—		18,672			121			—			18,794
Accrued expenses and other payables	19,233		—		137,095			8,105			—			164,433
Advance payments received from customers	—		—		95,573			807			—			96,380
Current maturities of long-term debt	—		—		3,859			181			—			4,040
Total current liabilities	19,234		—		814,943			17,993			—			852,170

LONG-TERM DEBT, net of current maturities	1,100,000		—		1,743,548			250,146			—			3,093,694
OTHER NONCURRENT LIABILITIES	—		—		13,782			3,897			—			17,679

EQUITY:
Partners’ equity	1,942,147		—		1,556,474			622,024			(2,178,362		)	1,942,283
Accumulated other comprehensive loss	—		—		—			(136		)	—			(136		)
Noncontrolling interests	—		—		—			—			544,147			544,147
Total equity	1,942,147		—		1,556,474			621,888			(1,634,215		)	2,486,294
Total liabilities and equity	$	3,061,381	$	—	$	4,128,747		$	893,924		$	(1,634,215	)	$	6,449,837

(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	March 31, 2015
	NGL Energy
	Partners LP		NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	29,115	$	—	$	9,757		$	2,431		$	—		$	41,303
Accounts receivable—trade, net of allowance for doubtful accounts	—		—		1,007,001			17,225			—			1,024,226
Accounts receivable—affiliates	5		—		16,610			583			—			17,198
Inventories	—		—		440,026			1,736			—			441,762
Prepaid expenses and other current assets	—		—		104,528			16,327			—			120,855
Total current assets	29,120		—		1,577,922			38,302			—			1,645,344

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,093,018			524,371			—			1,617,389
GOODWILL	—		—		1,372,690			30,071			—			1,402,761
INTANGIBLE ASSETS, net of accumulated amortization	17,834		—		1,195,896			74,613			—			1,288,343
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		217,600			255,073			—			472,673
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,363,792		—		(1,319,724		)	(44,068		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,834,738		—		56,690			—			(1,891,428		)	—
LOAN RECEIVABLE—AFFILIATE	—		—		8,154			—			—			8,154
OTHER NONCURRENT ASSETS	—		—		110,120			2,717			—			112,837
Total assets	$	3,245,484	$	—	$	4,312,366		$	881,079		$	(1,891,428	)	$	6,547,501

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—	$	820,441		$	12,939		$	—		$	833,380
Accounts payable—affiliates	—		—		25,690			104			—			25,794
Accrued expenses and other payables	19,690		—		165,819			9,607			—			195,116
Advance payments received from customers	—		—		53,903			331			—			54,234
Current maturities of long-term debt	—		—		4,413			59			—			4,472
Total current liabilities	19,690		—		1,070,266			23,040			—			1,112,996

LONG-TERM DEBT, net of current maturities	1,100,000		—		1,395,100			250,199			—			2,745,299
OTHER NONCURRENT LIABILITIES	—		—		12,262			3,824			—			16,086

EQUITY:
Partners’ equity	2,125,794		—		1,834,738			604,125			(2,438,754		)	2,125,903
Accumulated other comprehensive loss	—		—		—			(109		)	—			(109		)
Noncontrolling interests	—		—		—			—			547,326			547,326
Total equity	2,125,794		—		1,834,738			604,016			(1,891,428		)	2,673,120
Total liabilities and equity	$	3,245,484	$	—	$	4,312,366		$	881,079		$	(1,891,428	)	$	6,547,501

(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—	$	3,153,370		$	49,442		$	(9,617	)	$	3,193,195

COST OF SALES	—			—		3,009,777			5,610			(9,561		)	3,005,826

OPERATING COSTS AND EXPENSES:
Operating	—			—		77,166			22,663			(56		)	99,773
General and administrative	—			—		24,538			4,760			—			29,298
Depreciation and amortization	—			—		45,006			11,755			—			56,761
Loss (gain) on disposal or impairment of assets, net	—			—		1,294			(3		)	—			1,291

Operating Income (Loss)	—			—		(4,411		)	4,657			—			246

OTHER INCOME (EXPENSE):
Equity in earnings (losses) of unconsolidated entities	—			—		(23		)	2,455			—			2,432
Interest expense	(17,913		)	—		(11,351		)	(2,381		)	74			(31,571		)
Other income, net	—			—		1,916			113			(74		)	1,955

Income (Loss) Before Income Taxes	(17,913		)	—		(13,869		)	4,844			—			(26,938		)

INCOME TAX (PROVISION) BENEFIT	—			—		2,793			(7		)	—			2,786

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	(9,130		)	—		1,946			—			7,184			—

Net Income (Loss)	(27,043		)	—		(9,130		)	4,837			7,184			(24,152		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,166		)	(16,166		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(2,891		)	(2,891		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(27,043	)	$	—	$	(9,130	)	$	4,837		$	(11,873	)	$	(43,209	)

(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—	$	5,325,186		$	55,364		$	(24	)	$	5,380,526
												.
COST OF SALES	—			—		5,161,935			17,554			(24		)	5,179,465

OPERATING COSTS AND EXPENSES:
Operating	—			—		80,084			17,335			—			97,419
General and administrative	—			—		36,360			5,279			—			41,639
Depreciation and amortization	—			—		38,999			11,100			—			50,099
Loss (gain) on disposal or impairment of assets, net	—			—		4,216			(82		)	—			4,134

Operating Income	—			—		3,592			4,178			—			7,770

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,310			1,387			—			3,697
Interest expense	(17,201		)	—		(9,956		)	(1,506		)	12			(28,651		)
Other expense, net	—			—		(524		)	(81		)	(12		)	(617		)

Income (Loss) Before Income Taxes	(17,201		)	—		(4,578		)	3,978			—			(17,801		)

INCOME TAX (PROVISION) BENEFIT	—			—		1,951			(29		)	—			1,922

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	(2,023		)	—		604			—			1,419			—

Net Income (Loss)	(19,224		)	—		(2,023		)	3,949			1,419			(15,879		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(11,056		)	(11,056		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,345		)	(3,345		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(19,224	)	$	—	$	(2,023	)	$	3,949		$	(12,982	)	$	(30,280	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—	$	6,650,251		$	100,621		$	(19,208	)	$	6,731,664

COST OF SALES	—			—		6,333,438			14,022			(19,083		)	6,328,377

OPERATING COSTS AND EXPENSES:
Operating	—			—		164,790			43,022			(125		)	207,687
General and administrative	—			—		81,208			10,571			—			91,779
Depreciation and amortization	—			—		90,545			26,047			—			116,592
Loss (gain) on disposal or impairment of assets, net	—			—		1,715			(3		)	—			1,712

Operating Income (Loss)	—			—		(21,445		)	6,962			—			(14,483		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,872			8,278			—			11,150
Interest expense	(35,714		)	—		(22,344		)	(4,463		)	148			(62,373		)
Other income, net	—			—		691			237			(148		)	780

Income (Loss) Before Income Taxes	(35,714		)	—		(40,226		)	11,014			—			(64,926		)

INCOME TAX (PROVISION) BENEFIT	—			—		2,286			(38		)	—			2,248

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	(33,730		)	—		4,210			—			29,520			—

Net Income (Loss)	(69,444		)	—		(33,730		)	10,976			29,520			(62,678		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(31,525		)	(31,525		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(6,766		)	(6,766		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(69,444	)	$	—	$	(33,730	)	$	10,976		$	(8,771	)	$	(100,969	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—	$	8,952,772		$	76,421		$	(53	)	$	9,029,140

COST OF SALES	—			—		8,676,881			36,690			(53		)	8,713,518

OPERATING COSTS AND EXPENSES:
Operating	—			—		146,145			18,710			—			164,855
General and administrative	—			—		64,124			5,388			—			69,512
Depreciation and amortization	—			—		77,545			11,929			—			89,474
Loss (gain) on disposal or impairment of assets, net	—			—		4,774			(208		)	—			4,566

Operating Income (Loss)	—			—		(16,697		)	3,912			—			(12,785		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		4,875			1,387			—			6,262
Interest expense	(29,593		)	—		(18,058		)	(1,517		)	23			(49,145		)
Other income (expense), net	—			—		(1,056		)	71			(23		)	(1,008		)

Income (Loss) Before Income Taxes	(29,593		)	—		(30,936		)	3,853			—			(56,676		)

INCOME TAX (PROVISION) BENEFIT	—			—		993			(106		)	—			887

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	(29,606		)	—		337			—			29,269			—

Net Income (Loss)	(59,199		)	—		(29,606		)	3,747			29,269			(55,789		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(20,437		)	(20,437		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,410		)	(3,410		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(59,199	)	$	—	$	(29,606	)	$	3,747		$	5,422		$	(79,636	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(27,043	)	$	—	$	(9,130	)	$	4,837		$	7,184	$	(24,152	)

Other comprehensive loss	—			—		—			(19		)	—		(19		)

Comprehensive income (loss)	$	(27,043	)	$	—	$	(9,130	)	$	4,818		$	7,184	$	(24,171	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

	Three Months Ended September 30, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (2)			Finance Corp. (2)		Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(19,224	)	$	—	$	(2,023	)	$	3,949		$	1,419	$	(15,879	)

Other comprehensive income (loss)	—			—		4			(26		)	—		(22		)

Comprehensive income (loss)	$	(19,224	)	$	—	$	(2,019	)	$	3,923		$	1,419	$	(15,901	)

(2) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(69,444	)	$	—	$	(33,730	)	$	10,976		$	29,520	$	(62,678	)

Other comprehensive loss	—			—		—			(27		)	—		(27		)

Comprehensive income (loss)	$	(69,444	)	$	—	$	(33,730	)	$	10,949		$	29,520	$	(62,705	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

	Six Months Ended September 30, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (2)			Finance Corp. (2)		Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(59,199	)	$	—	$	(29,606	)	$	3,747		$	29,269	$	(55,789	)

Other comprehensive income (loss)	—			—		189			(26		)	—		163

Comprehensive income (loss)	$	(59,199	)	$	—	$	(29,417	)	$	3,721		$	29,269	$	(55,626	)

(2) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(34,469	)	$	—	$	173,058		$	35,506		$	174,095

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—		(184,680		)	(37,596		)	(222,276		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(150,546		)	—			(150,546		)
Cash flows from commodity derivatives	—			—		43,032			—			43,032
Proceeds from sales of assets	—			—		3,565			2			3,567
Investments in unconsolidated entities	—			—		(2,700		)	(4,226		)	(6,926		)
Distributions of capital from unconsolidated entities	—			—		5,652			2,555			8,207
Loan for natural gas liquids facility	—			—		(3,913		)	—			(3,913		)
Payments on loan for natural gas liquids facility	—			—		3,546			—			3,546
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Net cash used in investing activities	—			—		(301,665		)	(39,265		)	(340,930		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,311,500			43,200			1,354,700
Payments on revolving credit facilities	—			—		(963,000		)	(43,600		)	(1,006,600		)
Payments on other long-term debt	—			—		(2,274		)	(70		)	(2,344		)
Debt issuance costs	49			—		(180		)	(1,249		)	(1,380		)
Contributions from general partner	45			—		—			—			45
Contributions from noncontrolling interest owners	—			—		—			6,613			6,613
Distributions to partners	(154,824		)	—		—			—			(154,824		)
Distributions to noncontrolling interest owners	—			—		—			(17,780		)	(17,780		)
Taxes paid on behalf of equity incentive plan participants	—			—		(19,083		)	—			(19,083		)
Common unit repurchases	(3,650		)	—		—			—			(3,650		)
Net changes in advances with consolidated entities	186,776			—		(203,533		)	16,757			—
Other	—			—		(33		)	(79		)	(112		)
Net cash provided by financing activities	28,396			—		123,397			3,792			155,585
Net increase (decrease) in cash and cash equivalents	(6,073		)	—		(5,210		)	33			(11,250		)
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	23,042		$	—	$	4,547		$	2,464		$	30,053

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(23,563	)	$	—	$	(56,019	)	$	17,947		$	(61,635	)

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—		(81,710		)	(1,141		)	(82,851		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(657,514		)	(1,250		)	(658,764		)
Cash flows from commodity derivatives	—			—		4,327			—			4,327
Proceeds from sales of assets	—			—		8,741			—			8,741
Investments in unconsolidated entities	—			—		(6,106		)	(20,284		)	(26,390		)
Distributions of capital from unconsolidated entities	—			—		2,774			1,875			4,649
Net cash used in investing activities	—			—		(729,488		)	(20,800		)	(750,288		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,923,500			56,000			1,979,500
Payments on revolving credit facilities	—			—		(1,766,000		)	(38,000		)	(1,804,000		)
Issuance of notes	400,000			—		—			—			400,000
Payments on other long-term debt	—			—		(4,173		)	(2		)	(4,175		)
Debt issuance costs	(7,478		)	—		(1,720		)	—			(9,198		)
Contributions from general partner	395			—		—			—			395
Distributions to partners	(111,008		)	—		—			—			(111,008		)
Distributions to noncontrolling interest owners	—			—		—			(8,654		)	(8,654		)
Proceeds from sale of common units, net of offering costs	370,446			—		—			—			370,446
Net changes in advances with consolidated entities	(627,132		)	—		632,995			(5,863		)	—
Net cash provided by financing activities	25,223			—		784,602			3,481			813,306
Net increase (decrease) in cash and cash equivalents	1,660			—		(905		)	628			1,383
Cash and cash equivalents, beginning of period	1,181			—		8,728			531			10,440
Cash and cash equivalents, end of period	$	2,841		$	—	$	7,823		$	1,159		$	11,823

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and six months ended September 30, 2015. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10—K for the fiscal year ended March 31, 2015 (“Annual Report”).

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2015, our operations include:

Crude Oil Logistics

Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts whenever possible. When back-to-back physical contracts are not optimal, we enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma. We seek to manage exposure to price fluctuations by entering into purchase and sale contracts of similar volumes based on similar indexes and by hedging exposure due to fluctuations in actual volumes and scheduled volumes. We use our transportation assets to move crude oil from the wellhead to the highest value market. Spreads between crude oil prices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets.

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The following table summarizes the range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended September 30,
2015	$	38.24	$	56.96	$	45.09
2014	91.16		105.34		91.16

Six Months Ended September 30,
2015	$	38.24	$	61.43	$	45.09
2014	91.16		107.26		91.16

We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Water Solutions

Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling new wells. The primary customers of our Wyoming facility have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our Colorado facilities have committed to deliver to our facilities all wastewater produced at wells in a designated area. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most customers of our other facilities are not under volume commitments, although certain of our facilities are connected to producer locations by pipeline.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, wholesalers, refiners, and petrochemical plants. Our liquids segment owns 19 terminals and a salt dome storage facility, operates a fleet of leased railcars, and leases underground storage capacity. We attempt to reduce our exposure to price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

Our wholesale liquids business is a “cost-plus” business that can be affected by both price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage, and capital costs plus an acceptable margin. The margin we realize in our wholesale liquids business is substantially less on a per gallon basis than the margin we realize in our retail propane business.

Weather conditions and gasoline blending can have a significant impact on the demand for propane and butane, and sales volumes and prices are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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The following table summarizes the range of low and high spot propane prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of our main pricing hubs, for the periods indicated and the prices at period end:

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price Per Gallon						Spot Price Per Gallon
	Low		High		At Period End		Low		High		At Period End
Three Months Ended September 30,
2015	$	0.30	$	0.46	$	0.44	$	0.35	$	0.48	$	0.47
2014	1.00		1.10		1.03		0.99		1.11		1.04

Six Months Ended September 30,
2015	$	0.28	$	0.51	$	0.44	$	0.32	$	0.57	$	0.47
2014	0.96		1.13		1.03		0.99		1.13		1.04

The following table summarizes the range of low and high spot butane prices per gallon at Mt. Belvieu, Texas for the periods indicated and the prices at period end:

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended September 30,
2015	$	0.48	$	0.63	$	0.63
2014	1.21		1.30		1.22

Six Months Ended September 30,
2015	$	0.46	$	0.68	$	0.63
2014	1.20		1.30		1.22

We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Retail Propane

Our retail propane segment is a “cost-plus” business that sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions can have a significant impact on our sales volumes and prices, as a large portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

A significant factor affecting the profitability of our retail propane segment is our ability to maintain our product margin. Product margin is the difference between our sales prices and our total product costs, including transportation and storage. We monitor wholesale propane prices daily and adjust our retail prices accordingly. We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

The retail propane business is both weather-sensitive and subject to seasonal volume variations due to propane’s primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum products primarily in the Gulf Coast, Southeast, and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, and Magellan pipelines. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminals owned by third parties.

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The following table summarizes the range of low and high spot gasoline prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended September 30,
2015	$	54.78	$	85.89	$	58.35
2014	105.84		127.68		108.78

Six Months Ended September 30,
2015	$	54.78	$	90.15	$	58.35
2014	105.84		131.46		108.78

The following table summarizes the range of low and high spot diesel prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended September 30,
2015	$	58.00	$	77.28	$	63.53
2014	111.30		125.16		111.30

Six Months Ended September 30,
2015	$	58.00	$	84.68	$	63.53
2014	111.30		128.10		111.30

Acquisitions

As described below, we completed numerous acquisitions during the year ended March 31, 2015 and the six months ended September 30, 2015. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

Year Ending March 31, 2016

· In August 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas.

· We are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the six months ended September 30, 2015, we purchased eight water treatment and disposal facilities under these development agreements.

· During the six months ended September 30, 2015, we acquired four retail propane businesses.

Year Ended March 31, 2015

· In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility.

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· In November 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota.

· In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

· We are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under these development agreements.

· During the year ended March 31, 2015, we acquired eight retail propane businesses.

Summary Discussion of Operating Results for the Three Months Ended September 30, 2015

During the three months ended September 30, 2015, we generated operating income of $0.2 million, compared to operating income of $7.8 million during the three months ended September 30, 2014.

Our crude oil logistics segment generated an operating loss of $0.1 million during the three months ended September 30, 2015, compared to operating income of less than $0.1 million during the three months ended September 30, 2014. Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014, due primarily to lower crude oil prices, which resulted in increased market pressure. This was partially offset by an increase in service revenues, which benefitted from the fact that crude oil markets were in contango during the three months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which enabled us to better utilize our storage assets. The decrease in operating income was also partially offset by $3.4 million of expense recorded during the three months ended September 30, 2014 related to certain employee retention and severance costs associated with the Gavilon, LLC (“Gavilon Energy”) and TransMontaigne acquisitions.

Our water solutions segment generated operating income of $0.2 million during the three months ended September 30, 2015, compared to operating income of $14.8 million during the three months ended September 30, 2014. The acquisition and development of new facilities contributed to operating income during the three months ended September 30, 2015, although this impact was offset by a decrease in revenues from the sale of recovered hydrocarbons resulting from the decrease in crude oil prices.

Our liquids segment generated operating income of $20.4 million during the three months ended September 30, 2015, compared to operating income of $10.9 million during the three months ended September 30, 2014. Product margins for butane and other products were $12.1 million higher during the three months ended September 30, 2015 than during the three months ended September 30, 2014. In addition, Sawtooth, which we acquired in February 2015, generated $3.4 million of operating income during the three months ended September 30, 2015. These increases were partially offset by a decrease of $4.7 million in product margins for sales of propane.

Our retail propane segment generated an operating loss of $1.8 million during the three months ended September 30, 2015, compared to an operating loss of $3.1 million during the three months ended September 30, 2014. Due to the seasonal nature of demand for propane, sales volumes of our retail propane segment typically are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year. The primary reason for the decrease in the operating loss during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was increased margins on propane sales.

Our refined products and renewables segment generated an operating loss of $5.2 million during the three months ended September 30, 2015, compared to operating income of $8.8 million during the three months ended September 30, 2014. A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended September 30, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

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We recorded earnings from our equity method investments of $2.4 million during the three months ended September 30, 2015, compared to $3.7 million during the three months ended September 30, 2014. The decrease was due primarily to a decrease of $2.0 million in earnings from our investments in Glass Mountain Pipeline, LLC (“Glass Mountain”) and an ethanol production facility, partially offset by an increase of $1.1 million in earnings from our investments in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and Frontera Brownsville LLC (“Frontera”).

We incurred interest expense of $31.6 million during the three months ended September 30, 2015, compared to $28.7 million during the three months ended September 30, 2014. The increase was due primarily to borrowings to finance acquisitions and capital expenditures.

Consolidated Results of Operations

The following table summarizes our unaudited condensed consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Total revenues	$	3,193,195		$	5,380,526		$	6,731,664		$	9,029,140
Total cost of sales	3,005,826			5,179,465			6,328,377			8,713,518
Operating expenses	99,773			97,419			207,687			164,855
General and administrative expenses	29,298			41,639			91,779			69,512
Depreciation and amortization	56,761			50,099			116,592			89,474
Loss on disposal or impairment of assets, net	1,291			4,134			1,712			4,566
Operating income (loss)	246			7,770			(14,483		)	(12,785		)
Equity in earnings of unconsolidated entities	2,432			3,697			11,150			6,262
Interest expense	(31,571		)	(28,651		)	(62,373		)	(49,145		)
Other income (expense), net	1,955			(617		)	780			(1,008		)
Loss before income taxes	(26,938		)	(17,801		)	(64,926		)	(56,676		)
Income tax benefit	2,786			1,922			2,248			887
Net loss	(24,152		)	(15,879		)	(62,678		)	(55,789		)
Less: Net income allocated to general partner	(16,166		)	(11,056		)	(31,525		)	(20,437		)
Less: Net income attributable to noncontrolling interests	(2,891		)	(3,345		)	(6,766		)	(3,410		)
Net loss allocated to limited partners	$	(43,209	)	$	(30,280	)	$	(100,969	)	$	(79,636	)

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, and depreciation and amortization expense by segment below. The acquisitions described above under “ Acquisitions ” impact the comparability of our results of operations between our current and prior fiscal years.

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Non-GAAP Financial Measures

In addition to financial results reported in accordance with accounting principles generally accepted in the United States (“GAAP”), we have provided the non-GAAP financial measures of EBITDA and Adjusted EBITDA. These non-GAAP financial measures are not intended to be a substitute for those reported in accordance with GAAP. These measures may be different from non-GAAP financial measures used by other entities, even when similar terms are used to identify such measures.

We define EBITDA as net income (loss) attributable to parent equity, plus interest expense, income tax provision (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, and equity-based compensation expense. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our refined products and renewables segment, as described below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

Other than for our refined products and renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record a realized gain or loss. We do not draw such a distinction between realized and unrealized gains and losses on derivatives of our refined products and renewables segment. The primary hedging strategy of our refined products and renewables segment is to hedge against the risk of declines in the value of inventory over the course of the contract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuation adjustment” row in the table below reflects the excess of the market value of the inventory of our refined products and renewables segment at the balance sheet date over its cost. We add this to Adjusted EBITDA because the gains and losses associated with derivative contracts of this segment, which are intended primarily to hedge inventory holding risk, also impact Adjusted EBITDA.

The following table reconciles net loss to our EBITDA and Adjusted EBITDA (each as hereinafter defined), which are non-GAAP financial measures:

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Net loss	$	(24,152	)	$	(15,879	)	$	(62,678	)	$	(55,789	)
Net income attributable to noncontrolling interests	(2,891		)	(3,345		)	(6,766		)	(3,410		)
Net loss attributable to parent equity		(27,043	)		(19,224	)		(69,444	)		(59,199	)
Interest expense	29,520			27,929			58,168			48,446
Income tax benefit	(2,805		)	(1,933		)	(2,284		)	(898		)
Depreciation and amortization	53,299			48,366			107,467			92,716
EBITDA	52,971			55,138			93,907			81,065
Net unrealized gains on derivatives	(6,286		)	(13,700		)	(2,746		)	(8,690		)
Inventory valuation adjustment	9,197			—			19,355			—
Lower of cost or market adjustments	414			2,837			(5,926		)	2,837
Loss on disposal or impairment of assets, net	1,294			4,150			1,713			4,608
Equity-based compensation expense (1)	9,448			13,745			49,680			21,659
Adjusted EBITDA	$	67,038		$	62,170		$	155,983		$	101,479

(1) The equity-based compensation expense in the table above may differ from the equity-based compensation expense reported in Note 11 to our condensed consolidated financial statements included in this Quarterly Report on Form 10—Q (“Quarterly Report”). Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 11 to our condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

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The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our condensed consolidated statements of operations and condensed consolidated statements of cash flows for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	53,299		$	48,366		$	107,467		$	92,716
Intangible asset amortization recorded to cost of sales	(1,700		)	(1,984		)	(3,401		)	(4,121		)
Depreciation and amortization of unconsolidated entities	(5,091		)	(5,734		)	(10,125		)	(8,615		)
Depreciation and amortization attributable to noncontrolling interests	10,253			9,451			22,651			9,494
Depreciation and amortization per condensed consolidated statements of operations	$	56,761		$	50,099		$	116,592		$	89,474

	Six Months Ended September 30,
	2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	107,467		$	92,716
Amortization of debt issuance costs recorded to interest expense	4,558			4,029
Depreciation and amortization of unconsolidated entities	(10,125		)	(8,615		)
Depreciation and amortization attributable to noncontrolling interests	22,651			9,494
Depreciation and amortization per condensed consolidated statements of cash flows	$	124,551		$	97,624

The following table reconciles interest expense per the EBITDA table above to interest expense reported in our condensed consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Interest expense per EBITDA table	$	29,520	$	27,929	$	58,168	$	48,446
Interest expense attributable to noncontrolling interests	1,781		622		3,337		622
Gain on extinguishment of debt of unconsolidated entities	—		—		693		—
Other	270		100		175		77
Interest expense per condensed consolidated statements of operations	$	31,571	$	28,651	$	62,373	$	49,145

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The following table summarizes expansion and maintenance capital expenditures for the periods indicated. This information has been prepared on the accrual basis, and excludes property, plant and equipment acquired in acquisitions.

	Capital Expenditures
	Expansion (1)		Maintenance (2)		Total
	(in thousands)
Three Months Ended September 30,
2015	$	87,419	$	15,452	$	102,871
2014	23,270		10,714		33,984

Six Months Ended September 30,
2015	$	200,532	$	26,006	$	226,538
2014	65,675		17,176		82,851

(1) Includes expansion capital expenditures for TLP of $3.9 million and $1.0 million during the three months ended September 30, 2015 and 2014, respectively, and $9.3 million and $1.0 million during the six months ended September 30, 2015 and 2014, respectively.

(2) Includes maintenance capital expenditures for TLP of $4.2 million and $0.1 million during the three months ended September 30, 2015 and 2014, respectively, and $7.1 million and $0.1 million during the six months ended September 30, 2015 and 2014, respectively.

The following tables reconcile Adjusted EBITDA to operating income for each of our reportable segments for the periods indicated:

	Three Months Ended September 30, 2015
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	(75	)	$	205		$	20,370		$	(1,765	)	$	(5,244	)	$	(13,245	)	$	246
Depreciation and amortization	10,053			22,416			2,745			8,909			11,152			1,486			56,761
Amortization recorded to cost of sales	63			—			261			—			1,376			—			1,700
Net unrealized (gains) losses on derivatives	1,484			(4,166		)	(3,331		)	(273		)	—			—			(6,286		)
Equity-based compensation expense	—			—			—			—			23			9,444			9,467
Inventory valuation adjustment	—			—			—			—			9,197			—			9,197
Lower of cost or market adjustments	14			—			—			—			400			—			414
Loss on disposal or impairment of assets, net	1,080			58			9			64			80			—			1,291
Equity in earnings (losses) of unconsolidated entities	474			(284		)	—			(94		)	2,336			—			2,432
Other income (expense), net	(1,812		)	479			105			228			(58		)	3,013			1,955
Depreciation and amortization of unconsolidated entities	2,492			319			—			—			2,280			—			5,091
Adjusted EBITDA attributable to noncontrolling interests	—			(639		)	—			(173		)	(14,418		)	—			(15,230		)
Adjusted EBITDA	$	13,773		$	18,388		$	20,159		$	6,896		$	7,124		$	698		$	67,038

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	Three Months Ended September 30, 2014
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	38		$	14,792		$	10,929		$	(3,062	)	$	8,822		$	(23,749	)	$	7,770
Depreciation and amortization	9,240			17,573			3,384			7,684			11,917			301			50,099
Amortization recorded to cost of sales	110			—			495			—			1,353			26			1,984
Net unrealized gains on derivatives	(664		)	(12,746		)	(124		)	(166		)	—			—			(13,700		)
Equity-based compensation expense	—			—			—			—			—			13,745			13,745
Lower of cost or market adjustments	2,621			—			216			—			—			—			2,837
Loss (gain) on disposal or impairment of assets, net	204			3,861			(109		)	259			1			(82		)	4,134
Equity in earnings (losses) of unconsolidated entities	1,918			(66		)	—			—			1,845			—			3,697
Other income (expense), net	(1,306		)	105			4			340			(140		)	380			(617		)
Depreciation and amortization of unconsolidated entities	2,420			228			—			—			3,086			—			5,734
Adjusted EBITDA attributable to noncontrolling interests	—			(89		)	—			27			(13,451		)	—			(13,513		)
Adjusted EBITDA	$	14,581		$	23,658		$	14,795		$	5,082		$	13,433		$	(9,379	)	$	62,170

	Six Months Ended September 30, 2015
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	11,885		$	(2,867	)	$	19,899		$	(2,465	)	$	27,776		$	(68,711	)	$	(14,483	)
Depreciation and amortization	20,055			43,262			7,749			17,615			25,327			2,584			116,592
Amortization recorded to cost of sales	125			—			522			—			2,754			—			3,401
Net unrealized (gains) losses on derivatives	714			(2,458		)	(740		)	(262		)	—			—			(2,746		)
Equity-based compensation expense	—			—			—			—			585			49,556			50,141
Inventory valuation adjustment	—			—			—			—			19,355			—			19,355
Lower of cost or market adjustments	(1,211		)	—			—			—			(4,715		)	—			(5,926		)
Loss (gain) on disposal or impairment of assets, net	1,000			710			(191		)	113			80			—			1,712
Equity in earnings (losses) of unconsolidated entities	2,327			12			—			(159		)	8,970			—			11,150
Other income (expense), net	(5,760		)	783			209			626			255			4,667			780
Depreciation and amortization of unconsolidated entities	4,965			620			—			—			4,540			—			10,125
Adjusted EBITDA attributable to noncontrolling interests	—			(1,824		)	—			(125		)	(32,169		)	—			(34,118		)
Adjusted EBITDA	$	34,100		$	38,238		$	27,448		$	15,343		$	52,758		$	(11,904	)	$	155,983

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	Six Months Ended September 30, 2014
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	1,501		$	13,885		$	10,016		$	(4,648	)	$	7,567		$	(41,106	)	$	(12,785	)
Depreciation and amortization	18,971			34,665			6,585			15,255			12,761			1,237			89,474
Amortization recorded to cost of sales	(116		)	—			988			—			1,614			1,635			4,121
Net unrealized (gains) losses on derivatives	(3,060		)	(6,571		)	1,140			(199		)	—			—			(8,690		)
Equity-based compensation expense	—			—			—			—			—			21,659			21,659
Lower of cost or market adjustments	2,621			—			216			—			—			—			2,837
Loss (gain) on disposal or impairment of assets, net	195			4,347			(139		)	300			1			(138		)	4,566
Equity in earnings of unconsolidated entities	3,033			26			—			—			3,203			—			6,262
Other income (expense), net	(2,107		)	17			10			927			(52		)	197			(1,008		)
Depreciation and amortization of unconsolidated entities	5,179			228			—			—			3,208			—			8,615
Adjusted EBITDA attributable to noncontrolling interests	—			(213		)	—			92			(13,451		)	—			(13,572		)
Adjusted EBITDA	$	26,217		$	46,384		$	18,816		$	11,727		$	14,851		$	(16,516	)	$	101,479

Segment Operating Results for the Three Months Ended September 30, 2015 and 2014

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our water solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. The results of operations of our liquids and retail propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months ended September 30, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

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Volumes

The following table summarizes the volume of product sold and water received for the periods indicated. Volumes shown in the following table include intersegment sales.

	Three Months Ended September 30,
Segment	2015	2014	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	21,404	21,549	(145	)

Water solutions
Water received (barrels)	54,719	38,251	16,468

Liquids
Propane sold (gallons)	243,663	240,234	3,429
Other products sold (gallons)	232,227	197,510	34,717

Retail propane
Propane sold (gallons)	23,095	23,551	(456	)
Distillates sold (gallons)	3,550	3,434	116

Refined products and renewables
Refined products sold (barrels)	24,148	21,194	2,954
Renewable products sold (barrels)	1,308	1,228	80

Revenues and Cost of Sales by Segment

The following table summarizes our revenues and cost of sales by segment for the periods indicated:

	Three Months Ended September 30,
	2015								2014
				Cost of			Product					Cost of			Product
	Revenues			Sales			Margin		Revenues			Sales			Margin
	(in thousands)
Crude oil logistics	$	1,009,852		$	984,993		$	24,859	$	2,121,199		$	2,093,744		$	27,455
Water solutions	47,494			(8,567		)	56,061		52,719			(9,439		)	62,158
Liquids	269,728			231,851			37,877		553,872			528,213			25,659
Retail propane	53,206			20,879			32,327		68,358			39,894			28,464
Refined products and renewables	1,826,187			1,789,943			36,244		2,607,220			2,550,851			56,369
Corporate and other	—			—			—		1,333			383			950
Eliminations	(13,272		)	(13,273		)	1		(24,175		)	(24,181		)	6
Total	$	3,193,195		$	3,005,826		$	187,369	$	5,380,526		$	5,179,465		$	201,061

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Operating Income (Loss) by Segment

The following table summarizes our operating income (loss) by segment for the periods indicated:

	Three Months Ended September 30,
Segment	2015			2014			Change
	(in thousands)
Crude oil logistics	$	(75	)	$	38		$	(113	)
Water solutions	205			14,792			(14,587		)
Liquids	20,370			10,929			9,441
Retail propane	(1,765		)	(3,062		)	1,297
Refined products and renewables	(5,244		)	8,822			(14,066		)
Corporate and other	(13,245		)	(23,749		)	10,504
Operating income	$	246		$	7,770		$	(7,524	)

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Three Months Ended September 30,
	2015			2014 (1)		Change
	(in thousands)
Revenues:
Crude oil sales	$	997,106		$	2,109,618	$	(1,112,512	)
Crude oil transportation and other	12,746			11,581		1,165
Total revenues (2)	1,009,852			2,121,199		(1,111,347		)
Expenses:
Cost of sales	984,993			2,093,744		(1,108,751		)
Operating expenses	12,851			12,432		419
General and administrative expenses	2,030			5,745		(3,715		)
Depreciation and amortization expense	10,053			9,240		813
Total expenses	1,009,927			2,121,161		(1,111,234		)
Segment operating income (loss)	$	(75	)	$	38	$	(113	)

(2) Revenues include $2.3 million and $10.1 million of intersegment sales during the three months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our crude oil logistics segment generated $997.1 million of revenue from crude oil sales during the three months ended September 30, 2015, selling 21.4 million barrels at an average price of $46.59 per barrel. During the three months ended September 30, 2014, our crude oil logistics segment generated $2.1 billion of revenue from crude oil sales, selling 21.5 million barrels at an average price of $97.90 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014.

Crude oil transportation and other revenues were $12.7 million during the three months ended September 30, 2015, compared to $11.6 million during the three months ended September 30, 2014. The increase is due primarily to crude oil markets being in contango during the three months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

Cost of Sales . Our cost of crude oil sold was $985.0 million during the three months ended September 30, 2015, as we sold 21.4 million barrels at an average cost of $46.02 per barrel. Our cost of sales during the three months ended September 30, 2015 was increased by $1.5 million of net unrealized losses on derivatives. During the three months ended September 30, 2014, our cost of crude oil sold was $2.1 billion, as we sold 21.5 million barrels at an average cost of $97.16 per barrel. Our cost of sales during the

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three months ended September 30, 2014 was reduced by $0.7 million of net unrealized gains on derivatives. The following table summarizes our product margins for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Crude oil sales revenues	$	997,106		$	2,109,618
Crude oil cost of sales	(984,993		)	(2,093,744		)
Crude oil product margin	$	12,113		$	15,874

Crude oil sold (barrels)	21,404			21,549

Product margin per barrel	$	0.57		$	0.74

Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014 due primarily to lower crude oil prices, which resulted in increased market pressure.

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $12.9 million during the three months ended September 30, 2015, compared to $12.4 million during the three months ended September 30, 2014. This increase was due primarily to higher repair and maintenance expense due to the timing of repairs and to losses on asset retirements, partially offset by lower incentive compensation expense, as incentive compensation expense for the three months ended September 30, 2015 is reported within “corporate and other,” rather than within the crude oil logistics segment, since we expect to pay these bonuses in common units.

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $2.0 million during the three months ended September 30, 2015, compared to $5.7 million during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 included $2.2 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $10.1 million during the three months ended September 30, 2015, compared to $9.2 million during the three months ended September 30, 2014.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Three Months Ended September 30,
	2015			2014			Change
	(in thousands)
Revenues:
Service fees	$	35,203		$	24,238		$	10,965
Recovered hydrocarbons	10,746			23,334			(12,588		)
Water transportation	—			5,147			(5,147		)
Other revenues	1,545			—			1,545
Total revenues	47,494			52,719			(5,225		)
Expenses:
Cost of sales—derivative gain (1)	(8,567		)	(12,373		)	3,806
Cost of sales—other	—			2,934			(2,934		)
Operating expenses	32,755			29,019			3,736
General and administrative expenses	685			774			(89		)
Depreciation and amortization expense	22,416			17,573			4,843
Total expenses	47,289			37,927			9,362
Segment operating income	$	205		$	14,792		$	(14,587	)

(1) Includes realized and unrealized (gains) losses.

The following tables summarize activity separated among the following categories:

· facilities we owned before June 30, 2014, which we refer to below as “existing facilities”;

· facilities we developed after June 30, 2014, which we refer to below as “recently developed facilities”; and

· facilities we acquired after June 30, 2014, which we refer to below as “recently acquired facilities”.

Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:

	Three Months Ended September 30,
	2015					2014
			Water	Fees Per				Water	Fees Per
	Service		Barrels	Water Barrel		Service		Barrels	Water Barrel
	Fees		Processed	Processed		Fees		Processed	Processed

Existing facilities	$	22,651	31,891	$	0.71	$	24,238	38,251	$	0.63
Recently developed facilities	4,440		7,561	0.59		—		—	—
Recently acquired facilities	8,112		15,267	0.53		—		—	—
Total	$	35,203	54,719	0.64		$	24,238	38,251	0.63

The decrease in the volume processed at our existing facilities during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed and recently acquired facilities due to the location of the facilities.

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Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:

	Three Months Ended September 30,
	2015					2014
	Recovered		Water	Revenue Per		Recovered		Water	Revenue Per
	Hydrocarbon		Barrels	Water Barrel		Hydrocarbon		Barrels	Water Barrel
	Revenue		Processed	Processed		Revenue		Processed	Processed

Existing facilities	$	6,526	31,891	$	0.20	$	23,334	38,251	$	0.61
Recently developed facilities	1,415		7,561	0.19		—		—	—
Recently acquired facilities	2,805		15,267	0.18		—		—	—
Total	$	10,746	54,719	0.20		$	23,334	38,251	0.61

The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices after September 30, 2014 and a decrease in the volume of hydrocarbons recovered per barrel of water processed.

Our water solutions segment generated $5.1 million of water transportation revenue during the three months ended September 30, 2014. These revenues related to our water transportation business, which we sold during September 2014.

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales during the three months ended September 30, 2015 was reduced by $4.2 million of net unrealized gains on derivatives and $4.4 million of net realized gains on derivatives. Our cost of sales during the three months ended September 30, 2014 was reduced by $12.7 million of net unrealized gains on derivatives and increased by $0.3 million of net realized losses on derivatives.

Our other cost of sales was $2.9 million during the three months ended September 30, 2014. These costs related primarily to our water transportation business, which we sold during September 2014.

Operating Expenses . The following table summarizes our operating expenses for the periods indicated:

	Three Months Ended September 30,
	2015		2014		Change
	(in thousands)
Existing facilities	$	21,813	$	29,019	$	(7,206	)
Recently developed facilities	2,765		—		2,765
Recently acquired facilities	8,177		—		8,177
Total	$	32,755	$	29,019	$	3,736

The decrease in operating expenses for existing facilities was due primarily to a loss of $4.0 million related to the sale of our water transportation business during September 2014, and to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $0.7 million during the three months ended September 30, 2015, compared to $0.8 million during the three months ended September 30, 2014.

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $22.4 million during the three months ended September 30, 2015, compared to $17.6 million during the three months ended September 30, 2014. Of this increase, $3.0 million related to recently acquired facilities and $0.7 million related to recently developed facilities.

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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Three Months Ended September 30,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Propane sales	$	98,770	$	240,933	$	(142,163	)
Other product sales	160,836		306,660		(145,824		)
Other revenues	10,122		6,279		3,843
Total revenues (2)	269,728		553,872		(284,144		)
Expenses:
Cost of sales—propane	95,903		233,390		(137,487		)
Cost of sales—other products	132,179		290,119		(157,940		)
Cost of sales—other	3,769		4,704		(935		)
Operating expenses	12,330		9,183		3,147
General and administrative expenses	2,432		2,163		269
Depreciation and amortization expense	2,745		3,384		(639		)
Total expenses	249,358		542,943		(293,585		)
Segment operating income	$	20,370	$	10,929	$	9,441

(1) During the three months ended September 30, 2015, we made certain changes in the way we attribute revenues and railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $10.8 million and $14.1 million of intersegment sales during the three months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our liquids segment generated $98.8 million of wholesale propane sales revenue during the three months ended September 30, 2015, selling 243.7 million gallons at an average price of $0.41 per gallon. During the three months ended September 30, 2014, our liquids segment generated $240.9 million of wholesale propane sales revenue, selling 240.2 million gallons at an average price of $1.00 per gallon.

Our liquids segment generated $160.8 million of other wholesale products sales revenue during the three months ended September 30, 2015, selling 232.2 million gallons at an average price of $0.69 per gallon. During the three months ended September 30, 2014, our liquids segment generated $306.7 million of other wholesale products sales revenue, selling 197.5 million gallons at an average price of $1.55 per gallon. The increase in the volume of other wholesale products sold was due to expanded operations.

Our liquids segment generated $10.1 million of other revenues during the three months ended September 30, 2015, compared to $6.3 million during the three months ended September 30, 2014. This revenue includes storage income and income generated from the operation of a terminal for a customer. This increase was due primarily to $5.2 million of revenue related to Sawtooth, which we acquired in February 2015.

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Cost of Sales . Our cost of wholesale propane sales was $95.9 million during the three months ended September 30, 2015, as we sold 243.7 million gallons at an average cost of $0.39 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2015 was reduced by less than $0.1 million of net unrealized gains on derivatives. During the three months ended September 30, 2014, our cost of wholesale propane sales was $233.4 million, as we sold 240.2 million gallons at an average cost of $0.97 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2014 was increased by $1.9 million of net unrealized losses on derivatives. The following table summarizes our product margins for propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Propane revenues	$	98,770		$	240,933
Propane cost of sales	(95,903		)	(233,390		)
Propane product margin	$	2,867		$	7,543

Propane sold (gallons)	243,663			240,234

Product margin per gallon	$	0.012		$	0.031

Propane prices declined during the three months ended September 30, 2015, which had an adverse impact on product margins.

Our cost of sales of other products was $132.2 million during the three months ended September 30, 2015, as we sold 232.2 million gallons at an average cost of $0.57 per gallon. Our cost of sales of other products during the three months ended September 30, 2015 was reduced by $3.3 million of net unrealized gains on derivatives. During the three months ended September 30, 2014, our cost of sales of other products was $290.1 million, as we sold 197.5 million gallons at an average cost of $1.47 per gallon. Our cost of sales of other products during the three months ended September 30, 2014 was reduced by $2.2 million of net unrealized gains on derivatives. The following table summarizes our per gallon product margins (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Other products revenues	$	160,836		$	306,660
Other products cost of sales	(132,179		)	(290,119		)
Other products product margin	$	28,657		$	16,541

Other products sold (gallons)	232,227			197,510

Product margin per gallon	$	0.123		$	0.084

Product margins during the three months ended September 30, 2015 benefitted from a high level of butane supply in the market, which lowered our product cost.

Operating Expenses . Our liquids segment incurred operating expenses of $12.3 million during the three months ended September 30, 2015, compared to $9.2 million during the three months ended September 30, 2014. The increase in operating expenses was due primarily to $1.1 million of expenses related to Sawtooth, which we acquired in February 2015, and to increased compensation expense.

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $2.4 million during the three months ended September 30, 2015, compared to $2.2 million during the three months ended September 30, 2014.

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $2.7 million during the three months ended September 30, 2015, compared to $3.4 million during the three months ended September 30, 2014.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Three Months Ended September 30,
	2015			2014			Change
	(in thousands)
Revenues:
Propane sales	$	36,119		$	48,552		$	(12,433	)
Distillate sales	7,678			11,530			(3,852		)
Other revenues	9,409			8,276			1,133
Total revenues	53,206			68,358			(15,152		)
Expenses:
Cost of sales—propane	11,921			27,434			(15,513		)
Cost of sales—distillates	5,783			9,840			(4,057		)
Cost of sales—other	3,175			2,620			555
Operating expenses	22,485			21,205			1,280
General and administrative expenses	2,698			2,637			61
Depreciation and amortization expense	8,909			7,684			1,225
Total expenses	54,971			71,420			(16,449		)
Segment operating loss	$	(1,765	)	$	(3,062	)	$	1,297

Revenues . Our retail propane segment generated revenue of $36.1 million from propane sales during the three months ended September 30, 2015, selling 23.1 million gallons at an average price of $1.56 per gallon. During the three months ended September 30, 2014, our retail propane segment generated $48.6 million of revenue from propane sales, selling 23.6 million gallons at an average price of $2.06 per gallon.

Our retail propane segment generated revenue of $7.7 million from distillate sales during the three months ended September 30, 2015, selling 3.6 million gallons at an average price of $2.16 per gallon. During the three months ended September 30, 2014, our retail propane segment generated $11.5 million of revenue from distillate sales, selling 3.4 million gallons at an average price of $3.36 per gallon.

Cost of Sales . Our cost of retail propane sales was $11.9 million during the three months ended September 30, 2015, as we sold 23.1 million gallons at an average cost of $0.52 per gallon. During the three months ended September 30, 2014, our cost of retail propane sales was $27.4 million, as we sold 23.6 million gallons at an average cost of $1.16 per gallon. The following table summarizes our product margins for retail propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Propane revenues	$	36,119		$	48,552
Propane cost of sales	(11,921		)	(27,434		)
Propane product margin	$	24,198		$	21,118

Propane sold (gallons)	23,095			23,551

Product margin per gallon	$	1.05		$	0.90

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Our cost of distillate sales was $5.8 million during the three months ended September 30, 2015, as we sold 3.6 million gallons at an average cost of $1.63 per gallon. During the three months ended September 30, 2014, our cost of distillate sales was $9.8 million, as we sold 3.4 million gallons at an average cost of $2.87 per gallon. The following table summarizes our product margins for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Distillate revenues	$	7,678		$	11,530
Distillate cost of sales	(5,783		)	(9,840		)
Distillate product margin	$	1,895		$	1,690

Distillate sold (gallons)	3,550			3,434

Product margin per gallon	$	0.53		$	0.49

Operating Expenses . Our retail propane segment incurred operating expenses of $22.5 million during the three months ended September 30, 2015, compared to $21.2 million during the three months ended September 30, 2014. The increase in operating expenses was due primarily to increased employee compensation expense in support of the growth of our business.

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $2.7 million during the three months ended September 30, 2015, compared to $2.6 million during the three months ended September 30, 2014.

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $8.9 million during the three months ended September 30, 2015, compared to $7.7 million during the three months ended September 30, 2014.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated:

	Three Months Ended September 30,
	2015			2014 (1)		Change
	(in thousands)
Revenues:
Refined products sales (2)	$	1,704,259		$	2,466,389	$	(762,130	)
Renewables sales	93,189			116,825		(23,636		)
Service fees	28,739			24,006		4,733
Total revenues	1,826,187			2,607,220		(781,033		)
Expenses:
Cost of sales—refined products	1,696,664			2,436,468		(739,804		)
Cost of sales—renewables	93,279			114,383		(21,104		)
Operating expenses	25,538			29,838		(4,300		)
General and administrative expenses	4,798			5,792		(994		)
Depreciation and amortization expense	11,152			11,917		(765		)
Total expenses	1,831,431			2,598,398		(766,967		)
Segment operating income (loss)	$	(5,244	)	$	8,822	$	(14,066	)

(1) During the three months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $0.3 million of intersegment sales during the three months ended September 30, 2015 that are eliminated in our condensed consolidated statement of operations.

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Revenues . Our refined products sales revenue was $1.7 billion during the three months ended September 30, 2015, selling 24.1 million barrels at an average price of $70.58 per barrel. Our refined products sales revenue was $2.5 billion during the three months ended September 30, 2014, selling 21.2 million barrels at an average price of $116.37 per barrel. The increase in revenues resulting from higher sales volumes was offset by a sharp decline in product prices. The increase in volumes was due primarily to the purchase of certain pipeline capacity allocations from other shippers during the second half of the fiscal year ended March 31, 2015.

Our renewables sales revenue was $93.2 million during the three months ended September 30, 2015, selling 1.3 million barrels at an average price of $71.25 per barrel. Our renewables sales revenue was $116.8 million during the three months ended September 30, 2014, selling 1.2 million barrels at an average price of $95.13 per barrel.

Our refined products and renewables segment generated $28.7 million of service fee revenue during the three months ended September 30, 2015, compared to $24.0 million during the three months ended September 30, 2014. The increase in service fee revenue was due primarily to the fact that one of TLP’s terminal facilities was temporarily out of service during the three months ended September 30, 2014, the contracting of additional available capacity to a third party for a three-year term beginning in May 2015, and the transfer of a contract obligation from NGL to a third party during the fiscal year ended March 31, 2015.

Cost of Sales . Our cost of refined products sales was $1.7 billion during the three months ended September 30, 2015, as we sold 24.1 million barrels at an average cost of $70.26 per barrel. Our cost of refined products sales was $2.4 billion during the three months ended September 30, 2014, as we sold 21.2 million barrels at an average cost of $114.96 per barrel. The following table summarizes our refined product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Refined products revenues	$	1,704,259		$	2,466,389
Refined products cost of sales	(1,696,664		)	(2,436,468		)
Refined products product margin	$	7,595		$	29,921

Refined products sold (barrels)	24,148			21,194

Product margin per barrel	$	0.315		$	1.412
Product margin per gallon	$	0.007		$	0.034

A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended September 30, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

Our cost of renewables sales was $93.3 million during the three months ended September 30, 2015, as we sold 1.3 million barrels at an average cost of $71.31 per barrel. Our cost of renewables sales was $114.4 million during the three months ended September 30, 2014, as we sold 1.2 million barrels at an average cost of $93.15 per barrel. The following table summarizes our renewables product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Three Months Ended September 30,
	2015			2014

Renewables revenues	$	93,189		$	116,825
Renewables cost of sales	(93,279		)	(114,383		)
Renewables product margin (loss)	$	(90	)	$	2,442

Renewable products sold (barrels)	1,308			1,228

Product margin (loss) per barrel	$	(0.069	)	$	1.989
Product margin (loss) per gallon	$	(0.002	)	$	0.047

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Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014 due primarily to lower renewables prices caused by increased import activity.

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $25.5 million during the three months ended September 30, 2015, compared to $29.8 million during the three months ended September 30, 2014. This decrease was due primarily to lower compensation expense related to post-acquisition synergies.

General and Administrative Expenses . Our refined products and renewables segment incurred general and administrative expenses of $4.8 million during the three months ended September 30, 2015, compared to $5.8 million during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $11.2 million during the three months ended September 30, 2015, compared to $11.9 million during the three months ended September 30, 2014.

Corporate and Other

The operating loss within “corporate and other” includes the following components for the periods indicated:

	Three Months Ended September 30,
	2015			2014			Change
	(in thousands)
Incentive compensation expense	$	(4,278	)	$	(13,817	)	$	9,539
Acquisition expenses	(566		)	(3,230		)	2,664
Other corporate expenses	(8,401		)	(6,702		)	(1,699		)
Total	$	(13,245	)	$	(23,749	)	$	10,504

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014, due primarily to lower expenses associated with discretionary employee bonuses.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $3.0 million of such expenses during the three months ended September 30, 2014 related to our acquisition of TransMontaigne.

The increase in other corporate expenses was due to the continued growth of our business.

Segment Operating Results for the Six Months Ended September 30, 2015 and 2014

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our water solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. Our refined products and renewables businesses were significantly expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the six months ended September 30, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

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Volumes

The following table summarizes the volume of product sold and water received for the periods indicated. Volumes shown in the following table include intersegment sales.

	Six Months Ended September 30,
Segment	2015	2014	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	45,087	40,806	4,281

Water solutions
Water received (barrels)	109,195	65,689	43,506

Liquids
Propane sold (gallons)	471,615	423,992	47,623
Other products sold (gallons)	424,214	384,235	39,979

Retail propane
Propane sold (gallons)	47,502	47,142	360
Distillates sold (gallons)	8,643	8,712	(69	)

Refined products and renewables
Refined products sold (barrels)	45,075	29,094	15,981
Renewable products sold (barrels)	2,683	2,490	193

Revenues and Cost of Sales by Segment

The following table summarizes our revenues and cost of sales by segment for the periods indicated:

	Six Months Ended September 30,
	2015									2014
				Cost of			Product						Cost of			Product
	Revenues			Sales			Margin			Revenues			Sales			Margin
	(in thousands)
Crude oil logistics	$	2,341,584		$	2,280,933		$	60,651		$	4,060,257		$	4,001,158		$	59,099
Water solutions	101,787			(4,960		)	106,747			100,033			1,134			98,899
Liquids	532,229			477,643			54,586			1,070,393			1,031,563			38,830
Retail propane	117,653			50,443			67,210			146,260			87,418			58,842
Refined products and renewables	3,669,362			3,555,256			114,106			3,724,717			3,665,164			59,553
Corporate and other	—			—			—			2,794			2,371			423
Eliminations	(30,951		)	(30,938		)	(13		)	(75,314		)	(75,290		)	(24		)
Total	$	6,731,664		$	6,328,377		$	403,287		$	9,029,140		$	8,713,518		$	315,622

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Operating Income (Loss) by Segment

The following table summarizes our operating income (loss) by segment for the periods indicated:

	Six Months Ended September 30,
Segment	2015			2014			Change
	(in thousands)
Crude oil logistics	$	11,885		$	1,501		$	10,384
Water solutions	(2,867		)	13,885			(16,752		)
Liquids	19,899			10,016			9,883
Retail propane	(2,465		)	(4,648		)	2,183
Refined products and renewables	27,776			7,567			20,209
Corporate and other	(68,711		)	(41,106		)	(27,605		)
Operating loss	$	(14,483	)	$	(12,785	)	$	(1,698	)

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Six Months Ended September 30,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Crude oil sales	$	2,309,889	$	4,038,673	$	(1,728,784	)
Crude oil transportation and other	31,695		21,584		10,111
Total revenues (2)	2,341,584		4,060,257		(1,718,673		)
Expenses:
Cost of sales	2,280,933		4,001,158		(1,720,225		)
Operating expenses	24,601		28,417		(3,816		)
General and administrative expenses	4,110		10,210		(6,100		)
Depreciation and amortization expense	20,055		18,971		1,084
Total expenses	2,329,699		4,058,756		(1,729,057		)
Segment operating income	$	11,885	$	1,501	$	10,384

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $6.2 million and $19.8 million of intersegment sales during the six months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our crude oil logistics segment generated $2.3 billion of revenue from crude oil sales during the six months ended September 30, 2015, selling 45.1 million barrels at an average price of $51.23 per barrel. During the six months ended September 30, 2014, our crude oil logistics segment generated $4.0 billion of revenue from crude oil sales, selling 40.8 million barrels at an average price of $98.97 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014. The increase in our sales volumes was due to expanded operations.

Crude oil transportation and other revenues were $31.7 million during the six months ended September 30, 2015, compared to $21.6 million during the six months ended September 30, 2014. The increase is due primarily to crude oil markets being in contango during the six months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

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Cost of Sales . Our cost of crude oil sold was $2.3 billion during the six months ended September 30, 2015, as we sold 45.1 million barrels at an average cost of $50.59 per barrel. Our cost of sales during the six months ended September 30, 2015 was increased by $0.7 million of net unrealized losses on derivatives. During the six months ended September 30, 2014, our cost of crude oil sold was $4.0 billion, as we sold 40.8 million barrels at an average cost of $98.05 per barrel. Our cost of sales during the six months ended September 30, 2014 was reduced by $3.1 million of net unrealized gains on derivatives. The following table summarizes our product margins for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Crude oil sales revenues	$	2,309,889		$	4,038,673
Crude oil cost of sales	(2,280,933		)	(4,001,158		)
Crude oil product margin	$	28,956		$	37,515

Crude oil sold (barrels)	45,087			40,806

Product margin per barrel	$	0.64		$	0.92

Per-barrel product margins were lower during the six months ended September 30, 2015 than during the six months ended September 30, 2014 due primarily to lower crude oil prices, which resulted in increased market pressure.

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $24.6 million during the six months ended September 30, 2015, compared to $28.4 million during the six months ended September 30, 2014. This decrease was due primarily to lower incentive compensation expense, as incentive compensation expense for the six months ended September 30, 2015 is reported within “corporate and other,” rather than within the crude oil logistics segment, since we expect to pay these bonuses in common units.

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $4.1 million during the six months ended September 30, 2015, compared to $10.2 million during the six months ended September 30, 2014. General and administrative expenses during the six months ended September 30, 2014 included $4.3 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $20.1 million during the six months ended September 30, 2015, compared to $19.0 million during the six months ended September 30, 2014.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Six Months Ended September 30,
	2015			2014			Change
	(in thousands)
Revenues:
Service fees	$	71,941		$	41,939		$	30,002
Recovered hydrocarbons	26,564			47,349			(20,785		)
Water transportation	—			10,745			(10,745		)
Other revenues	3,282			—			3,282
Total revenues	101,787			100,033			1,754
Expenses:
Cost of sales—derivative gain (1)	(4,960		)	(5,070		)	110
Cost of sales—other	—			6,204			(6,204		)
Operating expenses	64,949			48,748			16,201
General and administrative expenses	1,403			1,601			(198		)
Depreciation and amortization expense	43,262			34,665			8,597
Total expenses	104,654			86,148			18,506
Segment operating income (loss)	$	(2,867	)	$	13,885		$	(16,752	)

(1) Includes realized and unrealized (gains) losses.

The following tables summarize activity separated among the following categories:

· facilities we owned before March 31, 2014, which we refer to below as “existing facilities”;

· facilities we developed after March 31, 2014, which we refer to below as “recently developed facilities”; and

· facilities we acquired after March 31, 2014, which we refer to below as “recently acquired facilities”.

Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:

	Six Months Ended September 30,
	2015					2014
			Water	Fees Per				Water	Fees Per
	Service		Barrels	Water Barrel		Service		Barrels	Water Barrel
	Fees		Processed	Processed		Fees		Processed	Processed

Existing facilities	$	39,686	50,669	$	0.78	$	37,376	58,639	$	0.64
Recently developed facilities	7,898		13,466	0.59		—		—	—
Recently acquired facilities	24,357		45,060	0.54		4,563		7,050	0.65
Total	$	71,941	109,195	0.66		$	41,939	65,689	0.64

The decrease in the volume processed at our existing facilities during the six months ended September 30, 2015 compared to the six months ended September 30, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed and recently acquired facilities due to the location of the facilities.

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Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:

	Six Months Ended September 30,
	2015					2014
	Recovered		Water	Revenue Per		Recovered		Water	Revenue Per
	Hydrocarbon		Barrels	Water Barrel		Hydrocarbon		Barrels	Water Barrel
	Revenue		Processed	Processed		Revenue		Processed	Processed

Existing facilities	$	15,207	50,669	$	0.30	$	44,831	58,639	$	0.76
Recently developed facilities	3,459		13,466	0.26		—		—	—
Recently acquired facilities	7,898		45,060	0.18		2,518		7,050	0.36
Total	$	26,564	109,195	0.24		$	47,349	65,689	0.72

Our water solutions segment generated $10.7 million of water transportation revenue during the six months ended September 30, 2014. These revenues related to our water transportation business, which we sold during September 2014.

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expected to recover when processing the wastewater. Our cost of sales during the six months ended September 30, 2015 was reduced by $2.5 million of net unrealized gains on derivatives and $2.5 million of net realized gains on derivatives. Our cost of sales during the six months ended September 30, 2014 was reduced by $6.6 million of net unrealized gains on derivatives and increased by $1.5 million of net realized losses on derivatives.

Our other cost of sales was $6.2 million during the six months ended September 30, 2014. These costs related primarily to our water transportation business, which we sold during September 2014.

Operating Expenses . The following table summarizes our operating expenses for the periods indicated:

	Six Months Ended September 30,
	2015		2014		Change
	(in thousands)
Existing facilities	$	37,683	$	43,611	$	(5,928	)
Recently developed facilities	4,925		—		4,925
Recently acquired facilities	22,341		5,137		17,204
Total	$	64,949	$	48,748	$	16,201

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $1.4 million during the six months ended September 30, 2015, compared to $1.6 million during the six months ended September 30, 2014.

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $43.3 million during the six months ended September 30, 2015, compared to $34.7 million during the six months ended September 30, 2014. Of this increase, $7.1 million related to recently acquired facilities and $1.2 million related to recently developed facilities.

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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Six Months Ended September 30,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Propane sales	$	204,260	$	463,736	$	(259,476	)
Other product sales	308,347		595,075		(286,728		)
Other revenues	19,622		11,582		8,040
Total revenues (2)	532,229		1,070,393		(538,164		)
Expenses:
Cost of sales—propane	205,273		454,638		(249,365		)
Cost of sales—other products	265,347		568,640		(303,293		)
Cost of sales—other	7,023		8,285		(1,262		)
Operating expenses	22,301		18,248		4,053
General and administrative expenses	4,637		3,981		656
Depreciation and amortization expense	7,749		6,585		1,164
Total expenses	512,330		1,060,377		(548,047		)
Segment operating income	$	19,899	$	10,016	$	9,883

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $24.3 million and $55.5 million of intersegment sales during the six months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our liquids segment generated $204.3 million of wholesale propane sales revenue during the six months ended September 30, 2015, selling 471.6 million gallons at an average price of $0.43 per gallon. During the six months ended September 30, 2014, our liquids segment generated $463.7 million of wholesale propane sales revenue, selling 424.0 million gallons at an average price of $1.09 per gallon. The increase in the volume sold was due primarily to the expansion of an agreement under which we market the majority of the production from a fractionation facility.

Our liquids segment generated $308.3 million of other wholesale products sales revenue during the six months ended September 30, 2015, selling 424.2 million gallons at an average price of $0.73 per gallon. During the six months ended September 30, 2014, our liquids segment generated $595.1 million of other wholesale products sales revenue, selling 384.2 million gallons at an average price of $1.55 per gallon. The increase in the volume of other wholesale products sold was due to expanded operations.

Our liquids segment generated $19.6 million of other revenues during the six months ended September 30, 2015, compared to $11.6 million during the six months ended September 30, 2014. This revenue includes storage income and income generated from the operation of a terminal for a customer. This increase was due primarily to $10.0 million of revenue related to Sawtooth, which we acquired in February 2015.

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Cost of Sales . Our cost of wholesale propane sales was $205.3 million during the six months ended September 30, 2015, as we sold 471.6 million gallons at an average cost of $0.44 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2015 was increased by $0.9 million of net unrealized losses on derivatives. During the six months ended September 30, 2014, our cost of wholesale propane sales was $454.6 million, as we sold 424.0 million gallons at an average cost of $1.07 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2014 was increased by $1.7 million of net unrealized losses on derivatives. The following table summarizes our product margins for propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Propane revenues	$	204,260		$	463,736
Propane cost of sales	(205,273		)	(454,638		)
Propane product margin (loss)	$	(1,013	)	$	9,098

Propane sold (gallons)	471,615			423,992

Product margin (loss) per gallon	$	(0.002	)	$	0.021

Propane prices declined during the six months ended September 30, 2015, which had an adverse impact on product margins.

Our cost of sales of other products was $265.3 million during the six months ended September 30, 2015, as we sold 424.2 million gallons at an average cost of $0.63 per gallon. Our cost of sales of other products during the six months ended September 30, 2015 was reduced by $1.6 million of net unrealized gains on derivatives. During the six months ended September 30, 2014, our cost of sales of other products was $568.6 million, as we sold 384.2 million gallons at an average cost of $1.48 per gallon. Our cost of sales of other products during the six months ended September 30, 2014 was reduced by $0.8 million of net unrealized gains on derivatives. The following table summarizes our per gallon product margins (in thousands, except per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Other products revenues	$	308,347		$	595,075
Other products cost of sales	(265,347		)	(568,640		)
Other products product margin	$	43,000		$	26,435

Other products sold (gallons)	424,214			384,235

Product margin per gallon	$	0.101		$	0.069

Product margins during the six months ended September 30, 2015 benefitted from a high level of butane supply in the market, which lowered our product cost.

Operating Expenses . Our liquids segment incurred operating expenses of $22.3 million during the six months ended September 30, 2015, compared to $18.2 million during the six months ended September 30, 2014. The increase in operating expenses was due primarily to $2.3 million of expenses related to Sawtooth, which we acquired in February 2015, and to increased compensation expense.

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $4.6 million during the six months ended September 30, 2015, compared to $4.0 million during the six months ended September 30, 2014. The increase in general and administrative expenses was due primarily to $0.7 million of expenses related to Sawtooth, which we acquired in February 2015.

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $7.7 million during the six months ended September 30, 2015, compared to $6.6 million during the six months ended September 30, 2014. The increase in depreciation and amortization expense was due to $2.7 million of expense during the six months ended September 30, 2015 related to Sawtooth, which we acquired in February 2015. This increase was partially offset by $0.9 million of depreciation expense we recorded during the six months ended September 30, 2014 related to a natural gas liquids terminal that we sold in December 2014.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Six Months Ended September 30,
	2015			2014			Change
	(in thousands)
Revenues:
Propane sales	$	79,304		$	100,578		$	(21,274	)
Distillate sales	20,625			30,225			(9,600		)
Other revenues	17,724			15,457			2,267
Total revenues	117,653			146,260			(28,607		)
Expenses:
Cost of sales—propane	28,232			56,721			(28,489		)
Cost of sales—distillates	15,975			25,876			(9,901		)
Cost of sales—other	6,236			4,821			1,415
Operating expenses	46,256			42,687			3,569
General and administrative expenses	5,804			5,548			256
Depreciation and amortization expense	17,615			15,255			2,360
Total expenses	120,118			150,908			(30,790		)
Segment operating loss	$	(2,465	)	$	(4,648	)	$	2,183

Revenues . Our retail propane segment generated revenue of $79.3 million from propane sales during the six months ended September 30, 2015, selling 47.5 million gallons at an average price of $1.67 per gallon. During the six months ended September 30, 2014, our retail propane segment generated $100.6 million of revenue from propane sales, selling 47.1 million gallons at an average price of $2.13 per gallon.

Our retail propane segment generated revenue of $20.6 million from distillate sales during the six months ended September 30, 2015, selling 8.6 million gallons at an average price of $2.39 per gallon. During the six months ended September 30, 2014, our retail propane segment generated $30.2 million of revenue from distillate sales, selling 8.7 million gallons at an average price of $3.47 per gallon.

Cost of Sales . Our cost of retail propane sales was $28.2 million during the six months ended September 30, 2015, as we sold 47.5 million gallons at an average cost of $0.59 per gallon. During the six months ended September 30, 2014, our cost of retail propane sales was $56.7 million, as we sold 47.1 million gallons at an average cost of $1.20 per gallon. The following table summarizes our product margins for retail propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Propane revenues	$	79,304		$	100,578
Propane cost of sales	(28,232		)	(56,721		)
Propane product margin	$	51,072		$	43,857

Propane sold (gallons)	47,502			47,142

Product margin per gallon	$	1.08		$	0.93

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Our cost of distillate sales was $16.0 million during the six months ended September 30, 2015, as we sold 8.6 million gallons at an average cost of $1.85 per gallon. During the six months ended September 30, 2014, our cost of distillate sales was $25.9 million, as we sold 8.7 million gallons at an average cost of $2.97 per gallon. The following table summarizes our product margins for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Distillate revenues	$	20,625		$	30,225
Distillate cost of sales	(15,975		)	(25,876		)
Distillate product margin	$	4,650		$	4,349

Distillate sold (gallons)	8,643			8,712

Product margin per gallon	$	0.54		$	0.50

Operating Expenses . Our retail propane segment incurred operating expenses of $46.3 million during the six months ended September 30, 2015, compared to $42.7 million during the six months ended September 30, 2014. The increase in operating expenses was due primarily to increased employee compensation expense in support of the growth of our business.

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $5.8 million during the six months ended September 30, 2015, compared to $5.5 million during the six months ended September 30, 2014.

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $17.6 million during the six months ended September 30, 2015, compared to $15.3 million during the six months ended September 30, 2014.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. The resultant increase in revenues and cost of sales was offset by a sharp decline in product prices.

	Six Months Ended September 30,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Refined products sales (2)	$	3,413,208	$	3,452,612	$	(39,404	)
Renewables sales	199,342		248,099		(48,757		)
Service fees	56,812		24,006		32,806
Total revenues	3,669,362		3,724,717		(55,355		)
Expenses:
Cost of sales—refined products	3,356,161		3,419,480		(63,319		)
Cost of sales—renewables	199,095		245,684		(46,589		)
Operating expenses	51,401		31,462		19,939
General and administrative expenses	9,602		7,763		1,839
Depreciation and amortization expense	25,327		12,761		12,566
Total expenses	3,641,586		3,717,150		(75,564		)
Segment operating income	$	27,776	$	7,567	$	20,209

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $0.5 million of intersegment sales during the six months ended September 30, 2015 that are eliminated in our condensed consolidated statement of operations.

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Revenues . Our refined products sales revenue was $3.4 billion during the six months ended September 30, 2015, selling 45.1 million barrels at an average price of $75.72 per barrel. Our refined products sales revenue was $3.5 billion during the six months ended September 30, 2014, selling 29.1 million barrels at an average price of $118.67 per barrel.

Our renewables sales revenue was $199.3 million during the six months ended September 30, 2015, selling 2.7 million barrels at an average price of $74.30 per barrel. Our renewables sales revenue was $248.1 million during the six months ended September 30, 2014, selling 2.5 million barrels at an average price of $99.64 per barrel.

Our refined products and renewables segment generated $56.8 million of service fee revenues during the six months ended September 30, 2015, compared to $24.0 million during the six months ended September 30, 2014.

Cost of Sales . Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2015, as we sold 45.1 million barrels at an average cost of $74.46 per barrel. Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2014, as we sold 29.1 million barrels at an average cost of $117.53 per barrel. The following table summarizes our refined product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Refined products revenues	$	3,413,208		$	3,452,612
Refined products cost of sales	(3,356,161		)	(3,419,480		)
Refined products product margin	$	57,047		$	33,132

Refined products sold (barrels)	45,075			29,094

Product margin per barrel	$	1.266		$	1.139
Product margin per gallon	$	0.030		$	0.027

Per-barrel product margins were higher during the six months ended September 30, 2015 than during the six months ended September 30, 2014, due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year. Per-barrel product margins are typically higher for TransMontaigne’s operations than they are for the refined product operations we owned prior to the acquisition of TransMontaigne.

Our cost of renewables sales was $199.1 million during the six months ended September 30, 2015, as we sold 2.7 million barrels at an average cost of $74.21 per barrel. Our cost of renewables sales was $245.7 million during the six months ended September 30, 2014, as we sold 2.5 million barrels at an average cost of $98.67 per barrel. The following table summarizes our renewables product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Six Months Ended September 30,
	2015			2014

Renewables revenues	$	199,342		$	248,099
Renewables cost of sales	(199,095		)	(245,684		)
Renewables product margin	$	247		$	2,415

Renewable products sold (barrels)	2,683			2,490

Product margin per barrel	$	0.092		$	0.970
Product margin per gallon	$	0.002		$	0.023

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Per-barrel product margins were lower during the six months ended September 30, 2015 than during the six months ended September 30, 2014 due primarily to lower renewables prices caused by increased import activity.

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $51.4 million during the six months ended September 30, 2015, compared to $31.5 million during the six months ended September 30, 2014. This increase was due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year, compared to three months of the prior fiscal year.

General and Administrative Expenses. Our refined products and renewables segment incurred general and administrative expenses of $9.6 million during the six months ended September 30, 2015, compared to $7.8 million during the six months ended September 30, 2014. This increase was due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year, compared to three months of the prior fiscal year. General and administrative expenses during the six months ended September 30, 2014 were increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $25.3 million during the six months ended September 30, 2015, compared to $12.8 million during the six months ended September 30, 2014. This increase was due primarily to depreciation on TLP’s terminal assets and amortization of customer relationship intangible assets acquired in the business combination with TransMontaigne. Of the depreciation and amortization expense, TLP’s depreciation and amortization expense was $23.5 million and $10.3 million during the six months ended September 30, 2015 and 2014, respectively.

Corporate and Other

The operating loss within “corporate and other” includes the following components for the periods indicated:

	Six Months Ended September 30,
	2015			2014			Change
	(in thousands)
Incentive compensation expense	$	(51,292	)	$	(22,210	)	$	(29,082	)
Acquisition expenses	(631		)	(4,328		)	3,697
Other corporate expenses	(16,788		)	(14,568		)	(2,220		)
Total	$	(68,711	)	$	(41,106	)	$	(27,605	)

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were higher during the six months ended September 30, 2015 than during the six months ended September 30, 2014, due primarily to two factors described below.

As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, under which the number of units that vest is contingent upon the performance of our common units relative to the performance of other entities in the Alerian MLP Index. During the six months ended September 30, 2015, three tranches of these Performance Awards were granted, with vesting dates of July 1, 2015, July 1, 2016, and July 1, 2017, respectively. We recorded $18.1 million of expense related to the Performance Awards during the six months ended September 30, 2015, $16.1 million of which related to awards that vested on July 1, 2015.

We have also granted certain Service Awards, which vest contingent only on the continued service of the recipients. The number of outstanding Service Awards was higher at September 30, 2015 than at September 30, 2014. This was due in part to the addition of new employees as our business has expanded, and was due in part to increases in the number of Service Awards granted to certain employees following the Compensation Committee’s review of our compensation program. The expense associated with these Service Awards (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $21.6 million during the six months ended September 30, 2015, compared to $11.2 million during the six months ended September 30, 2014.

The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $11.6 million during the six months ended September 30, 2015, compared to $11.0 million during the six months ended September 30, 2014.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $3.7 million of such expenses during the six months ended September 30, 2014 related to our acquisition of TransMontaigne.

The increase in other corporate expenses was due to the continued growth of our business.

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $2.4 million during the three months ended September 30, 2015, compared to $3.7 million during the three months ended September 30, 2014. The decrease was due primarily to a decrease of $2.0 million in earnings

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from our investments in Glass Mountain and an ethanol production facility, partially offset by an increase of $1.1 million in earnings from our investments in BOSTCO and Frontera.

Equity in earnings of unconsolidated entities was $11.2 million during the six months ended September 30, 2015, compared to $6.3 million during the six months ended September 30, 2014. The increase was due primarily to $6.9 million of earnings from BOSTCO and Frontera that we acquired as part of our July 2014 acquisition of TransMontaigne, partially offset by a decrease of $1.8 million in earnings from our investments in Glass Mountain and an ethanol production facility.

Interest Expense

Interest expense includes interest expense on our revolving credit facilities and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations. Interest expense was $31.6 million during the three months ended September 30, 2015, compared to $28.7 million during the three months ended September 30, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (hereinafter defined) (the average balance outstanding on our Revolving Credit Facility was $1.6 billion during the three months ended September 30, 2015, compared to $1.0 billion during three months ended September 30, 2014), primarily to finance acquisitions and capital expenditures.

Interest expense was $62.4 million during the six months ended September 30, 2015, compared to $49.1 million during the six months ended September 30, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.6 billion during the six months ended September 30, 2015, compared to $1.0 billion during six months ended September 30, 2014), primarily to finance acquisitions and capital expenditures. The increase in interest expense was also due in part to the fact that we issued $400.0 million of fixed-rate notes during July 2014, and the interest rate on these notes has been higher than the interest rate on the Revolving Credit Facility. The increase in interest expense was also due in part to increased interest expense associated with TLP’s credit facility. This increase was due primarily to the fact that we did not acquire our ownership interest in TLP until July 2014.

Other Income (Expense), Net

The following table summarizes the components of other income (expense), net for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Interest income	$	2,823		$	633		$	6,700		$	1,224
Crude oil marketing arrangement	(1,887		)	(1,692		)	(5,835		)	(3,747		)
Other	1,019			442			(85		)	1,515
Other income (expense), net	$	1,955		$	(617	)	$	780		$	(1,008	)

Interest income relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility being used by a third party and a loan receivable from an equity method investee. Amounts reflected in the table above for crude oil marketing agreement relate to another party’s share of the profits generated from a joint marketing arrangement.

Income Tax Provision (Benefit)

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between

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the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

Income tax benefit was $2.8 million during the three months ended September 30, 2015, compared to $1.9 million during the three months ended September 30, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the three months ended September 30, 2015 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

Income tax benefit was $2.2 million during the six months ended September 30, 2015, compared to $0.9 million during the six months ended September 30, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the six months ended September 30, 2015 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

Noncontrolling Interests

Net income attributable to noncontrolling interests was $2.9 million during the three months ended September 30, 2015, compared to $3.3 million during the three months ended September 30, 2014.

Net income attributable to noncontrolling interests was $6.8 million during the six months ended September 30, 2015, compared to $3.4 million during the six months ended September 30, 2014. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired a 19.7% limited partner interest in TLP.

Seasonality

Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane business is in the residential market where propane is used primarily for home heating purposes. Consequently, for these two segments, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See “—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows.”

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

Our borrowing needs vary during the year due in part to the seasonal nature of our liquids business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and liquids segments are the greatest.

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date. Available cash for any quarter generally consists of all cash on hand at the end of that quarter, less the amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. TLP’s partnership agreement also requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in its partnership agreement) to its unitholders as of the record date.

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

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We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our Revolving Credit Facility, the issuance of common units to sellers of businesses we acquire, private placements of debt or equity securities, and public offerings of debt or equity securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

Credit Agreement

At September 30, 2015, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

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covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

At September 30, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

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net tangible assets,” and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The commitments under the TLP Credit Facility mature on July 31, 2018.

Cash and cash equivalents	$	791
Accounts receivable—trade	3,074
Accounts receivable—affiliates	679
Inventories	1,250
Prepaid expenses and other current assets	858
Property, plant and equipment, net	477,357
Goodwill	30,169
Intangible assets, net	61,696
Investments in unconsolidated entities	255,757
Other noncurrent assets	968
Accounts payable—trade	(6,760		)
Accounts payable—affiliates	(121		)
Net intercompany payable	(1,911		)
Accrued expenses and other payables	(7,054		)
Advanced payments received from customers	(151		)
Long-term debt	(249,600		)
Other noncurrent liabilities	(3,441		)
Net assets	$	563,561

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Revolving Credit Balances

The following table summarizes our revolving credit facility borrowings for the periods indicated:

	Average
	Daily		Lowest		Highest
	Outstanding		Balance		Balance
	(in thousands)
Six Months Ended September 30, 2015
Expansion capital borrowings	$	893,002	$	739,500	$	1,083,000
Working capital borrowings	672,921		582,500		756,000
TLP credit facility borrowings	253,247		245,000		263,400

Six Months Ended September 30, 2014
Expansion capital borrowings	$	346,855	$	114,000	$	578,500
Working capital borrowings	640,369		339,500		1,024,500
TLP credit facility borrowings	246,750		228,000		258,500

Cash Flows

The following table summarizes the sources (uses) of our cash flows for the periods indicated:

	Six Months Ended September 30,
Cash Flows Provided by (Used in)	2015			2014
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	74,014		$	19,091
Changes in operating assets and liabilities	100,081			(80,726		)

Operating activities	$	174,095		$	(61,635	)

Investing activities	(340,930		)	(750,288		)

Financing activities	155,585			813,306

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories.

In general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We borrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second fiscal quarters.

Investing Activities . Net cash used in investing activities was $340.9 million during the six months ended September 30, 2015, compared to $750.3 million during the six months ended September 30, 2014. The decrease in net cash used in investing activities was due primarily to:

· a $508.2 million decrease in cash paid for acquisitions during the six months ended September 30, 2015 due primarily to the July 2014 acquisition of TransMontaigne; and

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· a $38.7 million increase in cash flows from derivatives.

These decreases were partially offset by an increase in capital expenditures from $82.9 million during the six months ended September 30, 2014, $65.7 million of which was expansion capital and $17.2 million of which was maintenance capital (of this maintenance capital, $0.1 million related to TLP), to $222.3 million during the six months ended September 30, 2015, $196.3 million of which was expansion capital and $26.0 million of which was maintenance capital (of this maintenance capital, $7.1 million related to TLP).

Financing Activities . Net cash provided by financing activities was $155.6 million during the six months ended September 30, 2015, compared to $813.3 million during the six months ended September 30, 2014. The decrease in net cash provided by financing activities was due primarily to:

· $400.0 million in proceeds received from the issuance of the 2019 Notes during the six months ended September 30, 2014;

· $370.4 million in proceeds received from the sale of our common units during the six months ended September 30, 2014; and

· a $52.9 million increase in distributions paid to our partners and noncontrolling interest owners during the six months ended September 30, 2015.

These decreases were partially offset by a $172.6 million increase in borrowings on our revolving credit facilities (net of repayments) during the six months ended September 30, 2015.

The following table summarizes the distributions declared after our initial public offering:

			Amount		Amount Paid To		Amount Paid To
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 19, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491
January 24, 2014	February 4, 2014	February 14, 2014	0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754
July 24, 2014	August 4, 2014	August 14, 2014	0.5888		52,036		9,481
October 24, 2014	November 4, 2014	November 14, 2014	0.6088		53,902		11,141
January 26, 2015	February 6, 2015	February 13, 2015	0.6175		54,684		11,860
April 24, 2015	May 5, 2015	May 15, 2015	0.6250		59,651		13,446
July 23, 2015	August 3, 2015	August 14, 2015	0.6325		66,244		15,483
October 22, 2015	November 3, 2015	November 13, 2015	0.6400		67,305		16,277

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The following table summarizes the distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at the time of the business combination):

			Amount		Amount Paid		Amount Paid To
Date Declared	Record Date	Date Paid	Per Unit		To NGL		Other Partners
					(in thousands)		(in thousands)
October 13, 2014	October 31, 2014	November 7, 2014	$	0.6650	$	4,010	$	8,614
January 8, 2015	January 30, 2015	February 6, 2015	0.6650		4,010		8,614
April 13, 2015	April 30, 2015	May 7, 2015	0.6650		4,007		8,617
July 13, 2015	July 31, 2015	August 7, 2015	0.6650		4,007		8,617
October 12, 2015	October 30, 2015	November 6, 2015	0.6650		4,007		8,617

Unit Repurchase Program

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Contractual Obligations

The following table summarizes our contractual obligations at September 30, 2015 for our fiscal years ending thereafter:

			Six Months
			Ending
			March 31,		Year Ending March 31,
	Total		2016		2017		2018		2019		2020		Thereafter
	(in thousands)
Principal payments on long-term debt—
Expansion capital borrowings	$	1,083,000	$	—	$	—	$	—	$	1,083,000	$	—	$	—
Working capital borrowings	656,000		—		—		—		656,000		—		—
2019 Notes	400,000		—		—		—		—		400,000		—
2021 Notes	450,000		—		—		—		—		—		450,000
2022 Notes	250,000		—		—		25,000		50,000		50,000		125,000
TLP Credit Facility	249,600		—		—		—		249,600		—		—
Other long-term debt	9,134		1,891		2,879		2,129		1,413		344		478
Interest payments on long-term debt—
Revolving Credit Facility (1)	130,690		21,079		42,158		42,158		25,295		—		—
2019 Notes	82,000		10,250		20,500		20,500		20,500		10,250		—
2021 Notes	201,094		15,469		30,938		30,938		30,938		30,938		61,873
2022 Notes	74,812		8,313		16,625		16,209		13,300		9,975		10,390
TLP Credit Facility	19,242		3,395		6,789		6,789		2,269		—		—
Other long-term debt	783		165		274		177		94		53		20
Letters of credit	89,647		—		—		—		89,647		—		—
Future minimum lease payments under noncancelable operating leases	503,436		60,441		106,125		90,783		66,385		56,509		123,193
Future minimum throughput payments under noncancelable agreements (2)	477,963		56,753		85,349		85,435		84,643		74,811		90,972
Construction commitments (3)	584,560		247,593		336,967		—		—		—		—
Fixed-price commodity purchase commitments (4)	38,651		37,706		945		—		—		—		—
Index-price commodity purchase commitments (5)	600,941		567,806		33,135		—		—		—		—
Total contractual obligations	$	5,901,553	$	1,030,861	$	682,684	$	320,118	$	2,373,084	$	632,880	$	861,926

Purchase commitments (thousands):
Natural gas liquids fixed-price (gallons) (6)	61,618		59,854		1,764		—		—		—		—
Natural gas liquids index-price (gallons) (6)	526,956		479,557		47,399		—		—		—		—
Crude oil fixed-price (barrels) (6)	13		13		—		—		—		—		—
Crude oil index-price (barrels) (6)	7,982		7,982		—		—		—		—		—

(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 2015. See Note 8 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

(2)	At September 30, 2015, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.

(3)	At September 30, 2015, we had the following construction commitments:

	·	In October 2014, Grand Mesa Pipeline, LLC (“Grand Mesa”) completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. We anticipate that the pipeline will commence service in the second half of calendar year 2016. At September 30, 2015, the construction commitments for Grand Mesa were $562.8 million.

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In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets. As part of this acquisition, we also entered into a construction agreement to expand the storage capacity of the facility. We anticipate this project will be completed by the end of calendar year 2015. At September 30, 2015, the construction commitments for this project were $21.8 million.

(4)	At September 30, 2015, we had the following purchase commitments (in thousands):

Natural gas liquids fixed-price		$	38,073
Crude oil fixed-price		578

(5)	At September 30, 2015 , we had the following purchase commitments (in thousands):

Natural gas liquids index-price		$	264,790
Crude oil index-price		336,151

Index prices are based on a forward price curve at September 30, 2015. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2015 would result in a change of $52.7 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2015 would result in a change of $8.0 million in the value of our index-price crude oil purchase commitments.

(6)	At September 30, 2015, we had the following sales contract volumes (in thousands):

Natural gas liquids fixed-price (gallons)		179,849
Natural gas liquids index-price (gallons)		253,827
Crude oil fixed-price (barrels)		1,018
Crude oil index-price (barrels)		7,842

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our condensed consolidated financial statements included in this Quarterly Report.

Environmental Legislation

Please see our Annual Report for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Trends

Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the nine months ended March 31, 2015 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to $45.09 per barrel at September 30, 2015). While crude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impact volumes in our crude oil logistics business.

Since January 2015, crude oil markets have been in contango (a condition in which the forward crude price is greater than the spot price). Our crude oil logistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory and when we sell it. In addition, we are able to better use our storage assets when crude oil markets are in contango.

Our opportunity to generate revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. As described above, crude oil prices declined sharply during the year ended

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March 31, 2015. At current market prices, producers may reduce drilling activity, which could have an adverse impact on the volumes of our water solutions business.

A portion of the revenues of our water solutions business is generated from the sale of hydrocarbons that we recover when processing the wastewater. Because of this, lower crude oil prices result in lower per barrel revenues for our water solutions business.

An important element of our refined products and renewables segment relates to the marketing of refined products in the Southeast and East Coast regions. We purchase product in the Gulf Coast, transport the product on third party pipelines, and sell the product primarily at TLP’s refined products terminals. Most of the contracts with these customers are one year in duration, with pricing indexed to prices in the Gulf Coast at the date of sale plus a specified differential. To operate this business we maintain inventory in transit on the third party pipelines and at the destination terminals where we sell the product. The value of this inventory will increase or decrease as market prices change. In order to mitigate this risk, we enter into futures contracts, which are only available based on New York Harbor pricing. Because our contracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, the futures contracts are not a perfect hedge against our inventory holding risk. During any given quarter, spreads between prices in the Gulf Coast and New York Harbor could narrow or widen, which could reduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

During the three months ended September 30, 2015, prices for refined products declined. Gulf Coast prices, on which our sales contracts are based, declined more than the New York Harbor prices, on which our futures contracts are based, which had an adverse impact on our weighted-average cost of sales. Based on historical experience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during any individual quarter within the year, and that we should expect more volatility in weighted-average cost of sales among quarters within a fiscal year than we would expect during a full fiscal year.

The decline in crude oil prices has had an adverse impact on many participants in the energy markets, and the inherent risk of customer or counterparty nonperformance is higher when crude oil prices are low or in decline.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015—11, “Simplifying the Measurement of Inventory.” ASU No. 2015—11 requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our current accounting policies.

In April 2015, the FASB issued ASU No. 2015—03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015—03 requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At September 30, 2015, intangible assets on our condensed consolidated balance sheet include $16.1 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015—03, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015—03, will be reclassified as a reduction to long-term debt.

In May 2014, the FASB issued ASU No. 2014—09, “Revenue from Contracts with Customers.” ASU No. 2014—09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2018, and allows for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. The application of these accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, and changes in these accounting policies, could have a material effect on our consolidated financial statements.

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Revenue Recognition

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

Crude oil prices decreased significantly during our prior fiscal year, and crude oil prices have remained low during our current fiscal year. This has had an unfavorable impact on our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a significant portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and low crude oil prices have an adverse impact on these revenues. We will consider these factors in preparing our goodwill impairment assessment during the fourth quarter of our fiscal year. Our water solutions segment has $467.1 million of goodwill at September 30, 2015. If we later conclude that this goodwill is impaired, we will record a reduction to goodwill and a related impairment expense.

We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value.

We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We record impairments of equity method investments if we believe the decline in value is other than temporary.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Our condensed consolidated balance sheet at September 30, 2015 includes a liability of $4.8 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired.

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Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense is the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant and equipment using the straight-line method, which results in us recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipment in service, we develop assumptions about the useful economic lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.

Amortization of Intangible Assets

Amortization expense is the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in us recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. When we acquire intangible assets, we develop assumptions about the useful economic lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Tank Bottoms

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost within property, plant and equipment on our condensed consolidated balance sheets. We recover tank bottoms when the storage tanks are removed from service. The following table summarizes the tank bottoms reported in our condensed consolidated balance sheet at September 30, 2015:

	Volume
Product	(in barrels)	Value
	(in thousands)
Gasoline	219	$	25,710
Crude oil	231	19,320
Diesel	121	14,753
Renewables	41	4,220
Other	12	738
Total		$	64,741

Linefill

We have entered into long-term commitments to ship specified minimum volumes of crude oil on certain third-party owned pipelines. These agreements require that we maintain a certain minimum amount of crude oil in the pipeline to serve as linefill over the duration of the agreement. We report such linefill at historical cost within other noncurrent assets on our condensed consolidated balance sheets. At September 30, 2015, linefill was $35.1 million and consisted of 487,104 barrels of crude oil.

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Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their acquisition date fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously reported consolidated financial position and results of operations.

Inventories

Our inventories consist primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the reporting period. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventories would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventories to the recoverable amount. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale liquids business to our retail propane business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors.

The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index over specified periods of time (the “Performance Awards”).

We report unvested units as liabilities in our condensed consolidated balance sheets. When units vest and are issued, we record an increase to equity.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

A significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, and refined products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At September 30, 2015, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

The crude oil, natural gas liquids, and refined products industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined products.

We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, to protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

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Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales. The following table summarizes the hypothetical impact on the September 30, 2015 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase
	(Decrease)
	To Fair Value

Crude oil (crude oil logistics segment)	$	(4,063	)
Crude oil (water solutions segment)	(3,077		)
Propane (liquids segment)	1,956
Other products (liquids segment)	(325		)
Refined products (refined products and renewables segment)	(15,995		)
Renewables (refined products and renewables segment)	(10,950		)

Fair Value

We use observable market values for determining the fair value of our derivative instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13(a)—15(e) and 15(d)—15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the Securities and Exchange Commission and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure.

We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at September 30, 2015. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of September 30, 2015, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Other than changes that have resulted or may result from our acquisition of TransMontaigne, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We acquired TransMontaigne and certain related operations in July 2014, as described in Note 4 to our condensed consolidated financial statements included in this Quarterly Report. At this time, we continue to evaluate the business and internal controls and processes associated with TransMontaigne and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over this acquired business. We expect that our evaluation and integration efforts related to these operations will continue into future fiscal quarters.

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PART II

Item 1. Legal Proceedings

For information related to legal proceedings, please see the discussion under the caption “Legal Contingencies” in Note 10 to our unaudited condensed consolidated financial statements in Part I, Item 1, of this Quarterly Report on Form 10—Q, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A—“Risk Factors” in our Annual Report on Form 10—K for the year ended March 31, 2015.

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

Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our units. The following table summarizes the repurchase of common units during the three months ended September 30, 2015.

				Total Number of
				Common Units	Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part	of Common Units
	Common Units	Paid Per		of Publicly Announced	that May Yet Be Purchased
Period	Purchased	Common Unit		Program	Under the Program

July 1—31, 2015	—	—		—	—
August 1—31, 2015	—	—		—	—
September 1—30, 2015	157,626	$	23.16	157,626	$	41,349,748
Total	157,626	$	23.16	157,626	$	41,349,748

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Exhibit

4.1	*	Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
4.2	*	Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
10.1		Amendment No. 10 to Credit Agreement, dated as of July 31, 2015 and effective as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8—K (File No. 001—35172) filed on August 4, 2015)
12.1	*	Computation of ratios of earnings to fixed charges
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 Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*	Exhibits filed with this report.

	**	The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

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SIGNATURES

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

	NGL ENERGY PARTNERS LP

	By:	NGL Energy Holdings LLC, its general partner

Date: November 9, 2015		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: November 9, 2015		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit Number		Exhibit

4.1	*	Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
4.2	*	Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
10.1		Amendment No. 10 to Credit Agreement, dated as of July 31, 2015 and effective as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8—K (File No. 001—35172) filed on August 4, 2015)
12.1	*	Computation of ratios of earnings to fixed charges
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 Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*	Exhibits filed with this report.

	**	The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

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Part I Item 1. Financial Statements (unaudited)Note 1 Organization and Operations Note 2 Significant Accounting Policies Note 3 Loss Per Common Unit Note 4 Acquisitions Note 5 Property, Plant and Equipment Note 6 Goodwill Note 7 Intangible Assets Note 8 Long-term Debt Note 9 Income Taxes Note 10 Commitments and Contingencies Note 11 Equity Note 12 Fair Value Of Financial Instruments Note 13 Segments Note 14 Transactions with Affiliates Note 15 Condensed Consolidating Guarantor and Non-guarantor Financial Information Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

NGL 10-Q Quarter ended Sept. 30, 2015