NGL Energy Partners LP - Quarter Report: 2015 June (Form 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 June 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 (Do not check if a smaller reporting company)	Smaller reporting company o

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 August 3, 2015, there were 107,274,540 common units issued and outstanding.

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PART I

Item 1.	Financial Statements (Unaudited)	3

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

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

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

	Condensed Consolidated Statement of Changes in Equity for the three months ended June 30, 2015	6

	Condensed Consolidated Statements of Cash Flows for the three months ended June 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	49

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77

Item 4.	Controls and Procedures	78

PART II

Item 1.	Legal Proceedings	79

Item 1A.	Risk Factors	79

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	79

Item 3.	Defaults Upon Senior Securities	79

Item 4.	Mine Safety Disclosures	79

Item 5.	Other Information	79

Item 6.	Exhibits	79

Signatures		80

Index to Exhibits		81

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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. When used in this Quarterly Report, words 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, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations 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 anticipated, estimated, projected or expected. Among the key risk factors that may impact our consolidated financial position and results of operations are:

· the prices for 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 petroleum 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;

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

· 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 crude oil 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 laws and regulations to which we are subject, 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)

	June 30,			March 31,
	2015			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	43,506		$	41,303
Accounts receivable—trade, net of allowance for doubtful accounts of $4,827 and $4,367, respectively	905,196			1,024,226
Accounts receivable—affiliates	18,740			17,198
Inventories	489,064			441,762
Prepaid expenses and other current assets	130,889			120,855
Total current assets	1,587,395			1,645,344

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $236,863 and $202,959, respectively	1,743,584			1,617,389
GOODWILL	1,451,654			1,402,761
INTANGIBLE ASSETS, net of accumulated amortization of $248,497 and $220,517, respectively	1,251,478			1,288,343
INVESTMENTS IN UNCONSOLIDATED ENTITIES	474,221			472,673
LOAN RECEIVABLE—AFFILIATE	23,775			8,154
OTHER NONCURRENT ASSETS	110,544			112,837
Total assets	$	6,642,651		$	6,547,501

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	755,062		$	833,380
Accounts payable—affiliates	25,592			25,794
Accrued expenses and other payables	237,407			195,116
Advance payments received from customers	66,706			54,234
Current maturities of long-term debt	3,933			4,472
Total current liabilities	1,088,700			1,112,996

LONG-TERM DEBT, net of current maturities	2,968,069			2,745,299
OTHER NONCURRENT LIABILITIES	17,082			16,086

COMMITMENTS AND CONTINGENCIES

EQUITY:
General partner, representing a 0.1% interest, 104,286 and 103,899 notional units at June 30, 2015 and March 31, 2015, respectively	(35,097		)	(37,021		)
Limited partners, representing a 99.9% interest, 104,181,253 and 103,794,870 common units issued and outstanding at June 30, 2015 and March 31, 2015, respectively	2,056,852			2,162,924
Accumulated other comprehensive loss	(117		)	(109		)
Noncontrolling interests	547,162			547,326
Total equity	2,568,800			2,673,120
Total liabilities and equity	$	6,642,651		$	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 June 30,
	2015			2014
REVENUES:
Crude oil logistics	$	1,327,784		$	1,929,283
Water solutions	54,293			47,314
Liquids	248,985			475,157
Retail propane	64,447			77,902
Refined products and renewables	1,842,960			1,117,497
Other	—			1,461
Total Revenues	3,538,469			3,648,614

COST OF SALES:
Crude oil logistics	1,291,992			1,897,639
Water solutions	3,607			10,573
Liquids	232,276			462,016
Retail propane	29,564			47,524
Refined products and renewables	1,765,112			1,114,313
Other	—			1,988
Total Cost of Sales	3,322,551			3,534,053

OPERATING COSTS AND EXPENSES:
Operating	107,914			67,436
General and administrative	62,481			27,873
Depreciation and amortization	59,831			39,375
Loss on disposal or impairment of assets, net	421			432
Operating Loss	(14,729		)	(20,555		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	8,718			2,565
Interest expense	(30,802		)	(20,494		)
Other expense, net	(1,175		)	(391		)
Loss Before Income Taxes	(37,988		)	(38,875		)

INCOME TAX PROVISION	(538		)	(1,035		)

Net Loss	(38,526		)	(39,910		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER	(15,359		)	(9,381		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(3,875		)	(65		)

NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(57,760	)	$	(49,356	)

BASIC AND DILUTED LOSS PER COMMON UNIT	$	(0.56	)	$	(0.61	)

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	103,888,281			74,126,205

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 June 30,
	2015			2014

Net loss	$	(38,526	)	$	(39,910	)
Other comprehensive income (loss)	(8		)	185
Comprehensive loss	$	(38,534	)	$	(39,725	)

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

Three Months Ended June 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	(13,446		)	—	(59,651		)	—			(9,057		)	(82,154		)
Contributions	11			—	—			—			3,947			3,958
Business combinations	—			386,383	11,367			—			—			11,367
Net income (loss)	15,359			—	(57,760		)	—			3,875			(38,526		)
Other comprehensive loss	—			—	—			(8		)	—			(8		)
Other	—			—	(28		)	—			1,071			1,043
BALANCES AT JUNE 30, 2015	$	(35,097	)	104,181,253	$	2,056,852		$	(117	)	$	547,162		$	2,568,800

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)

	Three Months Ended June 30,
	2015			2014
OPERATING ACTIVITIES:
Net loss	$	(38,526	)	$	(39,910	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization	63,814			43,424
Non-cash equity-based compensation expense	36,294			7,769
Loss on disposal or impairment of assets, net	421			432
Provision for doubtful accounts	1,060			251
Net commodity derivative loss	41,243			17,485
Equity in earnings of unconsolidated entities	(8,718		)	(2,565		)
Distributions of earnings from unconsolidated entities	6,163			—
Other	(8		)	192
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable—trade	119,675			(2,875		)
Accounts receivable—affiliates	(1,542		)	6,335
Inventories	(47,017		)	(63,536		)
Prepaid expenses and other assets	(25,432		)	(14,993		)
Accounts payable—trade	(78,115		)	70,113
Accounts payable—affiliates	(202		)	(39,140		)
Accrued expenses and other liabilities	714			(184		)
Advance payments received from customers	12,005			26,408
Net cash provided by operating activities	81,829			9,206

INVESTING ACTIVITIES:
Purchases of long-lived assets	(122,110		)	(48,867		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(63,898		)	(15,869		)
Cash flows from commodity derivatives	(21,693		)	(9,967		)
Proceeds from sales of assets	1,931			989
Investments in unconsolidated entities	(2,149		)	(4,094		)
Distributions of capital from unconsolidated entities	3,156			—
Loan for facility under construction	(3,913		)	—
Payments on loan for facility under construction	1,600			—
Loan to affiliate	(15,621		)	—
Net cash used in investing activities	(222,697		)	(77,808		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	721,200			494,500
Payments on revolving credit facilities	(498,200		)	(681,000		)
Payments on other long-term debt	(1,629		)	(2,347		)
Debt issuance costs	(6		)	(2,194		)
Contributions from general partner	11			352
Contributions from noncontrolling interest owners	3,947			—
Distributions to partners	(73,097		)	(49,491		)
Distributions to noncontrolling interest owners	(9,057		)	(12		)
Proceeds from sale of common units, net of offering costs	—			338,033
Other	(98		)	—
Net cash provided by financing activities	143,071			97,841
Net increase in cash and cash equivalents	2,203			29,239
Cash and cash equivalents, beginning of period	41,303			10,440
Cash and cash equivalents, end of period	$	43,506		$	39,679

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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 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 June 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 treatment and 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.

· 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 21 owned terminals throughout the United States and its salt dome storage facility in Utah and railcar transportation services through its fleet of leased railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.

· 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, which 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 operations.

Note 2—Significant Accounting Policies

Basis of Presentation

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. The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. Investments that we do not have the ability to exercise control of, but do have the ability to exercise significant influence over, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet at March 31, 2015 is derived from audited financial statements.

We have made certain reclassifications to prior period financial statements to conform to classification methods used in fiscal year 2016. These reclassifications had no impact on previously reported amounts of equity or net income. 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 herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the 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. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the fiscal year ended March 31, 2015 included in our Annual Report on Form 10—K (“Annual Report”). Due to the seasonal nature of our liquids and retail propane operations and other factors, the results of operations for interim periods are not necessarily indicative of the results 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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 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 reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

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 apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. 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, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

· Level 1—Quoted prices (unadjusted) 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 quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and 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 significantly 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 the fair value measurement requires judgment, considering factors specific to the asset or liability.

Revenue Recognition

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

performed, and we record tank and other rentals over the term of the lease. Pursuant to terminaling service agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we take delivery of the wastewater at our treatment and disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included 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 concurrently 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 ended June 30, 2015 include $1.5 million 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:

	Three Months Ended June 30,
	2015		2014
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,172	$	25,984
Income taxes paid	$	4,083	$	1,005

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 the reconciliation of net loss to net cash provided by 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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Inventories consist of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Crude oil	$	109,227	$	145,412
Natural gas liquids—
Propane	52,572		44,535
Butane	19,999		8,668
Other	9,958		3,874
Refined products—
Gasoline	161,566		128,092
Diesel	91,364		59,097
Renewables	34,331		44,668
Other	10,047		7,416
Total	$	489,064	$	441,762

Investments in Unconsolidated Entities

In December 2013, as part of our acquisition of Gavilon, LLC (“Gavilon Energy”), we acquired a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”) and an interest in a limited liability company that owns an ethanol production facility in the Midwest. In June 2014, we acquired an interest in a limited liability company that operates a water supply company in the DJ Basin. On July 1, 2014, as part of our acquisition of TransMontaigne Inc. (“TransMontaigne”), we acquired the 2.0% general partner interest and a 19.7% limited partner interest in TLP, which owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interest in Frontera Brownsville LLC (“Frontera”), which are entities that own refined products storage facilities. We also own a 50% interest in a limited liability company that operates a retail propane business.

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:

		June 30,		March 31,
Entity	Segment	2015		2015
		(in thousands)
Glass Mountain (1)	Crude oil logistics	$	185,834	$	187,590
BOSTCO (2)	Refined products and renewables	239,299		238,146
Frontera (2)	Refined products and renewables	17,287		16,927
Water supply company	Water solutions	16,767		16,471
Ethanol production facility	Refined products and renewables	14,350		13,539
Retail propane company	Retail propane	684		—
Total		$	474,221	$	472,673

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

(1) When we acquired Gavilon Energy, we recorded the investment in Glass Mountain at fair value. Our investment in Glass Mountain exceeds our share of the historical net book value of Glass Mountain’s net assets by $76.3 million at June 30, 2015. This difference relates primarily to goodwill and customer relationships.

(2) When we acquired TransMontaigne, we recorded the investments in BOSTCO and Frontera at fair value. Our investments in BOSTCO and Frontera exceed our share of the historical net book value of BOSTCO’s and Frontera’s net assets by $14.9 million at June 30, 2015. This difference relates primarily to goodwill.

Other Noncurrent Assets

Other noncurrent assets consist of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Loan receivable (1)	$	56,605	$	58,050
Linefill (2)	35,060		35,060
Other	18,879		19,727
Total	$	110,544	$	112,837

(1) Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized 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 June 30, 2015, linefill consisted of 487,104 barrels of crude oil.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Accrued compensation and benefits	$	104,044	$	52,078
Excise and other tax liabilities	39,844		43,847
Derivative liabilities	27,321		27,950
Accrued interest	19,655		23,065
Product exchange liabilities	17,322		15,480
Other	29,221		32,696
Total	$	237,407	$	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 represents the other owners’ interests in these entities.

On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired a 19.7% limited partner interest in TLP. We have attributed 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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

interest include the distributions of available cash (as defined by TLP’s partnership agreement) attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s 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 a reasonable period of time (not to exceed 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 of our acquisitions during the year ended March 31, 2015 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. Also as described in Note 4, we made certain adjustments during the three months ended June 30, 2015 to our estimates of the acquisition date fair values of the assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2015.

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 are in the process of assessing the impact of this ASU on our consolidated financial statements.

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, at which time we will begin presenting debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. The ASU requires retrospective application for all prior periods presented.

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 was computed as follows:

	Three Months Ended June 30,
	2015			2014
	(in thousands, except unit and per unit amounts)
Net loss attributable to parent equity	$	(42,401	)	$	(39,975	)
Less: Net income allocated to general partner (1)	(15,359		)	(9,381		)
Less: Net loss allocated to subordinated unitholders (2)	—			4,013
Net loss allocated to common unitholders	$	(57,760	)	$	(45,343	)

Basic and diluted weighted average common units outstanding	103,888,281			74,126,205

Basic and diluted loss per common unit	$	(0.56	)	$	(0.61	)

(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 subsequent to June 30, 2014, we did not allocate any income or loss subsequent to that date to the subordinated unitholders. During the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding. The loss per subordinated unit was ($0.68) for the three months ended June 30, 2014.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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

Note 4—Acquisitions

Year Ending March 31, 2016

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 three months ended June 30, 2015, we purchased six water treatment and disposal facilities under these development agreements. On a combined basis, we paid $59.3 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 June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the year ending March 31, 2016. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	$	24,511
Buildings and leasehold improvements (7–30 years)	5,050
Land	547
Other (5 years)	30
Goodwill	45,809
Accrued expenses and other payables	(5,102		)
Other noncurrent liabilities	(174		)
Fair value of net assets acquired	$	70,671

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.

The operations of these water treatment and disposal facilities have been included in our condensed consolidated statement of operations since their acquisition dates. Our condensed consolidated statement of operations for the three months ended June 30, 2015 includes revenues of $1.0 million and an operating loss of $0.5 million that were generated by the operations of these facilities after we acquired them.

Retail Propane Acquisition

During the three months ended June 30, 2015, we completed an acquisition of a retail propane business that operates in the northeastern United States and paid $4.6 million of cash to acquire 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 June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the three months ended December 31, 2015. The operations of this retail propane business have been included in our condensed consolidated statement of operations since its acquisition date. Our condensed consolidated statement of operations for the three months ended June 30, 2015 includes revenues of $0.3 million and operating income of $0.1 million that were generated by the operations of this business after we acquired them.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Year Ended March 31, 2015

As described in Note 2, pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed 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. Certain of our acquisitions during the year ended March 31, 2015 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. These business combinations are described below.

Natural Gas Liquids Storage Acquisition

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 June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the three months ended December 31, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

	Estimated At
	June 30,			March 31,
	2015			2015			Change
	(in thousands)
Accounts receivable—trade	$	42		$	42		$	—
Prepaid expenses and other current assets	883			600			283
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	151,570			151,853			(283		)
Intangible assets:
Customer relationships (15 years)	85,000			85,000			—
Non-compete agreements (10 years)	12,000			12,000			—
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.

The acquisition method of accounting requires that executory contracts with unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain natural gas liquids storage lease commitments were at unfavorable terms relative to acquisition-date market conditions, we recorded a liability of $12.8 million related to these lease commitments in the acquisition accounting, and we amortized $1.5 million of this balance as an

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

increase to revenues during the three months ended June 30, 2015. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
2016 (nine months)	$	4,355
2017	4,905
2018	1,306
2019	88

Bakken Water Solutions Facilities

On November 21, 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 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 June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the three months ending September 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

	Estimated At
	June 30,			March 31,
	2015			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	6,721			6,560			161
Intangible asset:
Customer relationships (6 years)	22,000			22,000			—
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% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

During the three months ended June 30, 2015, we completed the acquisition accounting for this business combination. The following table presents 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.

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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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 over the course of the year. 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 three months ended June 30, 2015, we completed the acquisition accounting for 12 of these water treatment and disposal facilities. The following table presents 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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 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 remaining five water treatment and disposal facilities, and as a result, the estimates of fair value at June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the three months ending December 31, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

	Estimated At
	June 30,			March 31,
	2015			2015			Change
	(in thousands)
Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	$	18,922		$	18,922		$	—
Buildings and leasehold improvements (7–30 years)	4,549			4,549			—
Land	987			987			—
Other (5 years)	28			28			—
Goodwill	39,412			39,412			—
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 Acquisitions

During the year ended March 31, 2015, we completed eight acquisitions of retail propane businesses that operate in the northeastern, Midwest, and southern United States. On a combined basis, we paid $39.0 million of cash and issued 132,100 common units, valued at $3.7 million, in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

During the three months ended June 30, 2015, we completed the acquisition accounting for seven of these business combinations. The following table presents 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	$	1,913		$	1,913		$	—
Inventories	583			583			—
Prepaid expenses and other current assets	110			110			—
Property, plant and equipment:
Retail propane equipment (15–20 years)	10,821			10,821			—
Vehicles and railcars (5–7 years)	1,953			1,953			—
Buildings and leasehold improvements (30 years)	534			534			—
Land	455			455			—
Other (5–7 years)	90			90			—
Goodwill	8,097			8,097			—
Intangible assets:
Customer relationships (10–15 years)	16,763			16,763			—
Non-compete agreements (5–7 years)	400			400			—
Trade names (3–12 years)	950			950			—
Accounts payable—trade	(1,523		)	(1,523		)	—
Advance payments received from customers	(1,661		)	(1,661		)	—
Current maturities of long-term debt	(78		)	(78		)	—
Long-term debt, net of current maturities	(760		)	(760		)	—
Fair value of net assets acquired	$	38,647		$	38,647		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 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 remaining one of these business combinations, and as a result, the estimates of fair value at June 30, 2015 are subject to change. We expect to complete this process prior to finalizing our financial statements for the three months ending September 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

	Estimated At
	June 30,			March 31,
	2015			2015			Change
	(in thousands)
Accounts receivable—trade	$	324		$	324		$	—
Inventories	188			188			—
Property, plant and equipment:
Retail propane equipment (15–20 years)	2,356			2,356			—
Vehicles and railcars (5–7 years)	379			379			—
Buildings and leasehold improvements (30 years)	—			250			(250		)
Land	50			200			(150		)
Other (5–7 years)	26			26			—
Intangible assets:
Customer relationships (10–15 years)	800			800			—
Non-compete agreements (5–7 years)	100			100			—
Accounts payable—trade	—			(398		)	398
Advance payments received from customers	(87		)	(89		)	2
Fair value of net assets acquired	$	4,136		$	4,136		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Note 5—Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	June 30,			March 31,
Description and Estimated Useful Lives	2015			2015
	(in thousands)
Natural gas liquids terminal and storage assets (2–30 years)	$	133,284		$	132,851
Refined products terminal assets and equipment (20 years)	429,038			403,609
Retail propane equipment (2–30 years)	184,749			181,140
Vehicles and railcars (3–25 years)	182,055			180,679
Water treatment facilities and equipment (3–30 years)	358,118			317,317
Crude oil tanks and related equipment (2–40 years)	110,637			109,909
Barges and towboats (5–40 years)	75,966			59,848
Information technology equipment (3–7 years)	38,516			34,915
Buildings and leasehold improvements (3–40 years)	108,529			98,989
Land	99,593			107,098
Tank bottoms	64,803			62,656
Other (3–30 years)	34,490			34,415
Construction in progress	160,669			96,922
	1,980,447			1,820,348
Accumulated depreciation	(236,863		)	(202,959		)
Net property, plant and equipment	$	1,743,584		$	1,617,389

Depreciation expense was $35.8 million and $18.5 million during the three months ended June 30, 2015 and 2014, respectively.

Product volumes required for the operation of storage tanks, known as tank bottoms, are recorded at historical cost. We recover tank bottoms when we no longer use the storage tanks or the storage tanks are removed from service. The following table summarizes the tank bottoms included in the table above:

	June 30, 2015			March 31, 2015
Product	Volume	Book Value		Volume	Book Value
	(in thousands)
Gasoline (barrels)	219	$	25,585	219	$	25,710
Crude oil (barrels)	232	19,507		184	16,835
Diesel (barrels)	121	14,753		124	15,153
Renewables (barrels)	41	4,220		41	4,220
Other	504	738		504	738
Total		$	64,803		$	62,656

Note 6—Goodwill

The changes in the balance of goodwill were as follows (in thousands):

Balance at March 31, 2015	$	1,402,761
Revisions to acquisition accounting (Note 4)	1,973
Acquisitions (Note 4)	46,920
Balance at June 30, 2015	$	1,451,654

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Goodwill by segment is as follows:

	June 30,		March 31,
	2015		2015
	(in thousands)
Crude oil logistics	$	579,846	$	579,846
Water solutions	447,626		401,656
Liquids	234,520		234,803
Retail propane	123,493		122,382
Refined products and renewables	66,169		64,074
Total	$	1,451,654	$	1,402,761

Note 7—Intangible Assets

Our intangible assets consist of the following:

		June 30, 2015				March 31, 2015
	Amortizable	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable—
Customer relationships	3–20 years	$	912,418	$	179,743	$	921,418	$	159,215
Pipeline capacity rights	30 years	119,636		3,568		119,636		2,571
Water facility development agreement	5 years	14,000		5,600		14,000		4,900
Executory contracts and other agreements	2–10 years	23,920		19,063		23,920		18,387
Non-compete agreements	2–10 years	26,771		11,629		26,662		10,408
Trade names	2–12 years	15,439		9,184		15,439		7,569
Debt issuance costs	5–10 years	55,171		19,710		55,165		17,467
Total amortizable		1,167,355		248,497		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		$	1,499,975	$	248,497	$	1,508,860	$	220,517

The weighted-average remaining amortization period for intangible assets is approximately 12 years.

Amortization expense is as follows:

	Three Months Ended June 30,
Recorded In	2015		2014
	(in thousands)
Depreciation and amortization	$	24,037	$	20,893
Cost of sales	1,701		2,137
Interest expense	2,282		1,912
Total	$	28,020	$	24,942

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 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 (nine months)	$	82,671
2017	104,093
2018	100,114
2019	90,904
2020	84,246
Thereafter	456,830
Total	$	918,858

Note 8—Long-Term Debt

Our long-term debt consists of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Revolving credit facility —
Expansion capital borrowings	$	890,000	$	702,500
Working capital borrowings	716,500		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	257,000		250,000
Other long-term debt	8,502		9,271
	2,972,002		2,749,771
Less: Current maturities	3,933		4,472
Long-term debt	$	2,968,069	$	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 June 30, 2015, our Revolving Credit Facility had a total capacity of $2.296 billion.

The Credit Agreement gives us the option to reallocate up to $400 million of capacity between the Working Capital Facility and the Expansion Capital Facility. In May 2015, we reallocated $125 million from the Working Capital Facility to the Expansion Capital Facility. The Expansion Capital Facility had a total capacity of $983.0 million for cash borrowings at June 30, 2015. At that date, we had outstanding borrowings of $890.0 million on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.313 billion for cash borrowings and letters of credit at June 30, 2015. At that date, we had outstanding borrowings of $716.5 million and outstanding letters of credit of $129.9 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, but 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.

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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 30, 2015 and 2014

based on our consolidated leverage ratio, as defined in the Credit Agreement. At June 30, 2015, the majority of the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at June 30, 2015 of 2.19%, calculated as the LIBOR rate of 0.19% plus a margin of 2.0%. At June 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 June 30, 2015, our leverage ratio was approximately 3.3 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 June 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 June 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”). We received net proceeds of $393.5 million, after the initial purchasers’ discount of $6.0 million and offering costs of $0.5 million.

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 prior to 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 June 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”). We received net proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and offering costs of $1.5 million.

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 prior to 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 June 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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 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 or 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 prior to 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 June 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 and (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 principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date of July 31, 2018.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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

Cash and cash equivalents	$	5,046
Accounts receivable—trade	7,402
Accounts receivable—affiliates	557
Inventories	1,404
Prepaid expenses and other current assets	975
Property, plant and equipment, net	478,450
Goodwill	30,169
Intangible assets, net	61,600
Investments in unconsolidated entities	256,585
Other noncurrent assets	2,546
Accounts payable—trade	(5,290		)
Accounts payable—affiliates	(118		)
Net intercompany payable	(2,258		)
Accrued expenses and other payables	(6,151		)
Advanced payments received from customers	(152		)
Long-term debt	(257,000		)
Other noncurrent liabilities	(3,301		)
Net assets	$	570,464

TLP may elect to have loans under the TLP Credit Facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. For the three months ended June 30, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.88%. 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 June 30, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $257.0 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) in the event 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 a defined financial performance measure within the TLP Credit Facility known as “Consolidated EBITDA.”

TLP’s Credit Facility is non-recourse to NGL.

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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at June 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 (nine months)	$	—	$	—	$	—	$	—	$	—	$	3,908	$	3,908
2017	—		—		—		—		—		2,729		2,729
2018	—		—		—		25,000		—		1,014		26,014
2019	1,606,500		—		—		50,000		257,000		479		1,913,979
2020	—		400,000		—		50,000		—		249		450,249
Thereafter	—		—		450,000		125,000		—		123		575,123
Total	$	1,606,500	$	400,000	$	450,000	$	250,000	$	257,000	$	8,502	$	2,972,002

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 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.

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 June 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 significant costs will not be incurred. 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,

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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 June 30, 2015 includes a liability of $4.6 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

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

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. Future minimum lease payments under these agreements at June 30, 2015 are as follows (in thousands):

Year Ending March 31,
2016 (nine months)	$	98,704
2017	104,877
2018	89,227
2019	64,815
2020	54,971
Thereafter	117,568
Total	$	530,162

Rental expense relating to operating leases was $33.8 million and $25.3 million during the three months ended June 30, 2015 and 2014, respectively.

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. In exchange, we are obligated to pay the minimum shipping fees in the event actual shipments are less than our allotted capacity. Future minimum throughput payments under these agreements at June 30, 2015 are as follows (in thousands):

Year Ending March 31,
2016 (nine months)	$	92,499
2017	81,935
2018	82,016
2019	81,222
2020	53,511
Thereafter	90,972
Total	$	482,155

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At June 30, 2015, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	66,117	$	42,163
Natural gas liquids index-price (gallons)	662,883	324,051
Crude oil index-price (barrels)	11,836	608,579
Sale commitments:
Natural gas liquids fixed-price (gallons)	170,769	120,156
Natural gas liquids index-price (gallons)	261,661	214,470
Crude oil fixed-price (barrels)	2,700	162,848
Crude oil index-price (barrels)	9,544	546,758

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 $39.5 million of our prepaid expenses and other current assets and $26.7 million of our accrued expenses and other payables at June 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. Prior to August 2014, the Partnership’s limited partner interest also included subordinated units. The subordination period ended in August 2014, at which time all remaining subordinated units were converted into common units on a one-for-one basis. Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Common Units Issued in Business Combination

During the three months ended June 30, 2015, we issued 386,383 common units as consideration for a water solutions facility acquisition.

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 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 unitholders 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 unitholders 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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

unitholders 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
	Total Quarterly						Distributions
	Distribution Per Unit						Unitholders		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	%

During the three months ended June 30, 2015, we distributed a total of $73.1 million ($0.6250 per common and general partner notional unit) to our unitholders of record on May 5, 2015, which included an incentive distribution of $13.4 million to our general partner. In July 2015, we declared a distribution of $0.6325 per common unit, to be paid on August 14, 2015 to unitholders of record on August 3, 2015. This distribution is expected to be $81.7 million in total, including amounts to be paid on common and general partner notional units and the amount to be paid on IDRs.

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.

The following table illustrates the percentage allocations of available cash from operating surplus between TLP’s unitholders 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 unitholders 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 unitholders 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
	Total Quarterly						Distributions
	Distribution Per Unit						Unitholders		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	%

During the three months ended June 30, 2015, TLP declared and paid a distribution of $0.6650 per unit. 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. In July 2015, TLP declared a distribution of $0.6650 per unit, which was paid on August 7, 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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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 three months ended June 30, 2015:

Unvested Service Award units at March 31, 2015		2,260,400
Units granted		308,823
Unvested Service Award units at June 30, 2015		2,569,223

The scheduled vesting of our Service Award units is summarized below:

Year Ending March 31,		Number of Units
2016 (nine months)		847,441
2017		846,141
2018		772,141
Thereafter		103,500
Unvested Service Award units at June 30, 2015		2,569,223

On July 1, 2015, 798,441 of the Service Award units vested. Of these units, recipients elected for us to withhold 252,307 common units for employee taxes, valued at $7.6 million. We issued the remaining 546,134 common units, valued at $16.5 million.

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.

We recorded expense related to Service Award units of $18.5 million and $7.9 million during the three months ended June 30, 2015 and 2014, respectively. We estimate that the future expense we will record on the unvested Service Award units at June 30, 2015 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 173,000 units. For purposes of this calculation, we used the closing price of our common units on June 30, 2015, which was $30.33.

Year Ending March 31,
2016 (nine months)	$	18,373
2017	21,211
2018	6,853
2019	1,399
2020	189
Total	$	48,025

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 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	18,503
Balance at June 30, 2015	$	24,657

The weighted-average fair value of the Service Award units at June 30, 2015 was $27.40 per common unit, which was calculated as the closing price of our common units on June 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 maximum number of units that could vest on these Performance Awards for each vesting tranche is summarized below:

		Maximum Performance
Vesting Date		Award Units
July 1, 2015		682,382
July 1, 2016		680,382
July 1, 2017		672,382
Total		2,035,146

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, 2015		July 1, 2012 through June 30, 2015
July 1, 2016		July 1, 2013 through June 30, 2016
July 1, 2017		July 1, 2014 through June 30, 2017

The percentage of the maximum Performance Award units that will vest will depend on the percentage of entities in the Index that NGL outperforms, as summarized in the table below:

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%

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 518,426 common units vested on July 1, 2015. Of these units, recipients elected for us to withhold 205,045 common units for employee taxes, valued at $6.2 million. We issued the remaining 313,381 common units, valued at $9.4 million, on July 1, 2015.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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 estimated fair value at June 30, 2015 for each vesting tranche, and the expense recorded during the three months ended June 30, 2015, is summarized below (in thousands):

	Fair Value of		Life-to-Date
Vesting Date	Unvested Awards		Expense Recorded
July 1, 2015	$	15,708	$	15,469
July 1, 2016	10,543		1,720
July 1, 2017	6,931		602
Total	$	33,182	$	17,791

We estimate that the future expense we will record on the unvested Performance Award units at June 30, 2015 will be as follows (in thousands), after taking into consideration an estimate of forfeitures. For purposes of this calculation, we used the June 30, 2015 fair value of the Performance Awards.

Year Ending March 31,
2016 (nine months)	$	8,902
2017	5,131
2018	747
Total	$	14,780

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	17,791
Balance at June 30, 2015	$	17,791

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 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 June 30, 2015, approximately 4.8 million common units remain available for issuance under the LTIP.

In August 2015, certain bonuses that were recorded as liabilities on the June 30, 2015 condensed consolidated balance sheet were paid in common units. We issued 463,239 common units related to these bonuses (before consideration of common units withheld for employee taxes).

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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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 June 30, 2015:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	2,879		$	(9,070	)
Level 2 measurements	40,011			(29,585		)
	42,890			(38,655		)

Netting of counterparty contracts (1)	(2,791		)	2,791
Net cash collateral provided	—			8,543
Commodity derivatives in condensed consolidated balance sheet	$	40,099		$	(27,321	)

(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 estimated fair values of our commodity derivative assets and liabilities reported in our condensed consolidated balance sheet at March 31, 2015:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	83,779		$	(3,969	)
Level 2 measurements	34,963			(28,764		)
	118,742			(32,733		)

Netting of counterparty contracts (1)	(1,804		)	1,804
Net cash collateral provided (held)	(56,660		)	2,979
Commodity derivatives in condensed consolidated balance sheet	$	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.

Our commodity derivative assets and liabilities are reported in the following accounts in our condensed consolidated balance sheets:

	June 30,			March 31,
	2015			2015
	(in thousands)
Prepaid expenses and other current assets	$	40,099		$	60,278
Accrued expenses and other payables	(27,321		)	(27,950		)
Net commodity derivative asset	$	12,778		$	32,328

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

The following table summarizes our open commodity derivative contract positions at June 30, 2015 and March 31, 2015. 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 June 30, 2015—
Cross-commodity (1)	July 2015–March 2016	99		$	(1,320	)
Crude oil fixed-price (2)	July 2015–December 2015	(1,209	)	102
Crude oil index-price (3)	July 2015–July 2015	198		624
Propane fixed-price (4)	July 2015–November 2017	485		(3,973		)
Refined products fixed-price (4)	July 2015–December 2015	(2,667	)	5,391
Other	July 2015–April 2016			3,411
				4,235
Net cash collateral provided				8,543
Net commodity derivatives in condensed consolidated balance sheet				$	12,778

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 (4)	April 2015–December 2016	193		(2,842		)
Refined products fixed-price (4)	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. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

(2) Crude oil fixed-price—Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3) Crude oil index-price—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index-price” represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4) 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. The contracts listed in this table as “fixed-price” represent derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

We recorded the following net losses from our commodity derivatives to cost of sales (in thousands):

Three Months Ended June 30,
2015	$	(41,243	)
2014	(17,485		)

Credit Risk

We maintain 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, as deemed appropriate.

The principal counterparties associated with our operations at June 30, 2015 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, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Failure of a counterparty to perform on a contract could result in our inability to 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 June 30, 2015, we had $1.6 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.2%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.0 million, based on borrowings outstanding at June 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 June 30, 2015, TLP had $257.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.93%. 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 June 30, 2015.

Fair Value of Fixed-Rate Notes

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

5.125% Notes due 2019	$	396,000
6.875% Notes due 2021	467,438
6.650% Notes due 2022	270,794

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes. These fair value estimates 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.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

Note 13—Segments

Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

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 incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our condensed consolidated financial statements.

	Three Months Ended June 30,
	2015			2014
	(in thousands)
Revenues:
Crude oil logistics—
Crude oil sales	$	1,312,783		$	1,929,055
Crude oil transportation and other	18,949			10,003
Water solutions—
Service fees	36,738			17,701
Recovered hydrocarbons	15,818			24,015
Water transportation	—			5,598
Other revenues	1,737			—
Liquids—
Propane sales	105,162			222,446
Other product sales	147,589			288,359
Other revenues	9,750			5,716
Retail propane—
Propane sales	43,185			52,026
Distillate sales	12,947			18,695
Other revenues	8,315			7,181
Refined products and renewables—
Refined products sales	1,708,949			986,223
Renewables sales	106,153			131,274
Service fees	28,073			—
Corporate and other	—			1,461
Elimination of intersegment sales	(17,679		)	(51,139		)
Total revenues	$	3,538,469		$	3,648,614

Depreciation and Amortization:
Crude oil logistics	$	10,002		$	9,731
Water solutions	20,846			17,092
Liquids	5,004			3,201
Retail propane	8,706			7,571
Refined products and renewables	14,175			844
Corporate and other	1,098			936
Total depreciation and amortization	$	59,831		$	39,375

Operating Income (Loss):
Crude oil logistics	$	11,960		$	1,463
Water solutions	(3,072		)	(907		)
Liquids	(471		)	(913		)
Retail propane	(700		)	(1,586		)
Refined products and renewables	33,020			(1,255		)
Corporate and other	(55,466		)	(17,357		)
Total operating loss	$	(14,729	)	$	(20,555	)

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

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

	Three Months Ended June 30,
	2015		2014
	(in thousands)
Additions to property, plant and equipment:
Crude oil logistics	$	62,639	$	41,949
Water solutions	60,489		7,462
Liquids	17,178		1,159
Retail propane	6,895		2,844
Refined products and renewables	15,695		—
Corporate and other	1,169		1,453
Total	$	164,065	$	54,867

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

	June 30,		March 31,
	2015		2015
	(in thousands)
Total assets:
Crude oil logistics	$	2,269,187	$	2,337,188
Water solutions	1,298,697		1,185,929
Liquids	737,114		713,547
Retail propane	528,934		542,476
Refined products and renewables	1,671,503		1,668,836
Corporate and other	137,216		99,525
Total	$	6,642,651	$	6,547,501

Long-lived assets, net:
Crude oil logistics	$	1,379,921	$	1,327,538
Water solutions	1,204,133		1,119,794
Liquids	546,204		534,560
Retail propane	468,007		467,652
Refined products and renewables	800,457		808,757
Corporate and other	47,994		50,192
Total	$	4,446,716	$	4,308,493

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 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 which we have purchased products and services and to which we have sold products and services. Approximately $7.0 million of these transactions during the three months ended June 30, 2015 represented 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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 30, 2015 and 2014

The above transactions are summarized in the following table:

	Three Months Ended June 30,
	2015		2014
	(in thousands)
Sales to SemGroup	$	37,438	$	25,982
Purchases from SemGroup	38,825		39,120
Sales to equity method investees	1,390		—
Purchases from equity method investees	30,948		36,276
Sales to entities affiliated with management	107		148
Purchases from entities affiliated with management	7,180		3,139

Accounts receivable from affiliates consist of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Receivables from SemGroup	$	17,975	$	13,443
Receivables from equity method investees	713		652
Receivables from entities affiliated with management	52		3,103
Total	$	18,740	$	17,198

Accounts payable to affiliates consist of the following:

	June 30,		March 31,
	2015		2015
	(in thousands)
Payables to SemGroup	$	17,391	$	11,546
Payables to equity method investees	4,649		6,788
Payables to entities affiliated with management	3,552		7,460
Total	$	25,592	$	25,794

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

Note 15—Subsequent Events

Water Solutions Facility Acquisition

As described in Note 4, 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 August 2015, we purchased one water treatment and disposal facility under these development agreements for $10.3 million of cash.

Note 16—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 the 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.

There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respective subsidiaries by dividend or loan, other than restrictions contained in TLP’s Credit Facility. None of the assets of the

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) represent 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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	June 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	$	22,693	$	—	$	13,642		$	7,171		$	—		$	43,506
Accounts receivable—trade, net of allowance for doubtful accounts	—		—		889,449			15,747			—			905,196
Accounts receivable—affiliates	11		—		18,172			557			—			18,740
Inventories	—		—		487,313			1,751			—			489,064
Prepaid expenses and other current assets	—		—		113,594			17,295			—			130,889
Total current assets	22,704		—		1,522,170			42,521			—			1,587,395

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,204,560			539,024			—			1,743,584
GOODWILL	—		—		1,419,487			32,167			—			1,451,654
INTANGIBLE ASSETS, net of accumulated amortization	16,936		—		1,170,731			63,811			—			1,251,478
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		217,636			256,585			—			474,221
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,371,288		—		(1,333,513		)	(37,775		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,727,335		—		73,107			—			(1,800,442		)	—
LOAN RECEIVABLE—AFFILIATE	—		—		23,775			—			—			23,775
OTHER NONCURRENT ASSETS	—		—		107,651			2,893			—			110,544
Total assets	$	3,138,263	$	—	$	4,405,604		$	899,226		$	(1,800,442	)	$	6,642,651

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—	$	744,886		$	10,176		$	—		$	755,062
Accounts payable—affiliates	1		—		25,473			118			—			25,592
Accrued expenses and other payables	16,624		—		213,484			7,299			—			237,407
Advance payments received from customers	—		—		66,248			458			—			66,706
Current maturities of long-term debt	—		—		3,863			70			—			3,933
Total current liabilities	16,625		—		1,053,954			18,121			—			1,088,700

LONG-TERM DEBT, net of current maturities	1,100,000		—		1,610,868			257,201			—			2,968,069
OTHER NONCURRENT LIABILITIES	—		—		13,447			3,635			—			17,082

EQUITY:
Partners’ equity	2,021,638		—		1,727,335			620,386			(2,347,604		)	2,021,755
Accumulated other comprehensive loss	—		—		—			(117		)	—			(117		)
Noncontrolling interests	—		—		—			—			547,162			547,162
Total equity	2,021,638		—		1,727,335			620,269			(1,800,442		)	2,568,800
Total liabilities and equity	$	3,138,263	$	—	$	4,405,604		$	899,226		$	(1,800,442	)	$	6,642,651

(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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

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

REVENUES	$	—		$	—	$	3,496,881		$	51,179		$	(9,591	)	$	3,538,469

COST OF SALES	—			—		3,323,661			8,412			(9,522		)	3,322,551

OPERATING COSTS AND EXPENSES:
Operating	—			—		87,624			20,359			(69		)	107,914
General and administrative	—			—		56,670			5,811			—			62,481
Depreciation and amortization	—			—		45,539			14,292			—			59,831
Loss on disposal or impairment of assets, net	—			—		421			—			—			421

Operating Income (Loss)	—			—		(17,034		)	2,305			—			(14,729		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,895			5,823			—			8,718
Interest expense	(17,801		)	—		(10,993		)	(2,082		)	74			(30,802		)
Other income (expense), net	—			—		(1,225		)	124			(74		)	(1,175		)

Income (Loss) Before Income Taxes	(17,801		)	—		(26,357		)	6,170			—			(37,988		)

INCOME TAX PROVISION	—			—		(507		)	(31		)	—			(538		)

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	(24,600		)	—		2,264			—			22,336			—

Net Income (Loss)	(42,401		)	—		(24,600		)	6,139			22,336			(38,526		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(15,359		)	(15,359		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,875		)	(3,875		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(42,401	)	$	—	$	(24,600	)	$	6,139		$	3,102		$	(57,760	)

(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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

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

REVENUES	$	—		$	—	$	3,627,586		$	21,057		$	(29	)	$	3,648,614

COST OF SALES	—			—		3,514,946			19,136			(29		)	3,534,053

OPERATING COSTS AND EXPENSES:
Operating	—			—		66,061			1,375			—			67,436
General and administrative	—			—		27,764			109			—			27,873
Depreciation and amortization	—			—		38,546			829			—			39,375
Loss (gain) on disposal or impairment of assets, net	—			—		558			(126		)	—			432

Operating Loss	—			—		(20,289		)	(266		)	—			(20,555		)

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,565			—			—			2,565
Interest expense	(12,392		)	—		(8,102		)	(11		)	11			(20,494		)
Other income (expense), net	—			—		(532		)	152			(11		)	(391		)

Loss Before Income Taxes	(12,392		)	—		(26,358		)	(125		)	—			(38,875		)

INCOME TAX PROVISION	—			—		(958		)	(77		)	—			(1,035		)

EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(27,583		)	—		(267		)	—			27,850			—

Net Loss	(39,975		)	—		(27,583		)	(202		)	27,850			(39,910		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(9,381		)	(9,381		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(65		)	(65		)

NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(39,975	)	$	—	$	(27,583	)	$	(202	)	$	18,404		$	(49,356	)

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

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

Net income (loss)	$	(42,401	)	$	—	$	(24,600	)	$	6,139		$	22,336	$	(38,526	)

Other comprehensive loss	—			—		—			(8		)	—		(8		)

Comprehensive income (loss)	$	(42,401	)	$	—	$	(24,600	)	$	6,131		$	22,336	$	(38,534	)

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

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

Net loss	$	(39,975	)	$	—	$	(27,583	)	$	(202	)	$	27,850	$	(39,910	)

Other comprehensive income	—			—		185			—			—		185

Comprehensive loss	$	(39,975	)	$	—	$	(27,398	)	$	(202	)	$	27,850	$	(39,725	)

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Three Months Ended June 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	$	(20,028	)	$	—	$	93,216		$	8,641		$	81,829

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—		(100,508		)	(21,602		)	(122,110		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(63,898		)	—			(63,898		)
Cash flows from commodity derivatives	—			—		(21,693		)	—			(21,693		)
Proceeds from sales of assets	—			—		1,931			—			1,931
Investments in unconsolidated entities	—			—		(2,149		)	—			(2,149		)
Distributions of capital from unconsolidated entities	—			—		3,156			—			3,156
Loan for facility under construction	—			—		(3,913		)	—			(3,913		)
Payments on loan for facility under construction	—			—		1,600			—			1,600
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Net cash used in investing activities	—			—		(201,095		)	(21,602		)	(222,697		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		704,000			17,200			721,200
Payments on revolving credit facilities	—			—		(488,000		)	(10,200		)	(498,200		)
Payments on other long-term debt	—			—		(1,599		)	(30		)	(1,629		)
Debt issuance costs	54			—		(60		)	—			(6		)
Contributions from general partner	11			—		—			—			11
Contributions from noncontrolling interest owners	—			—		—			3,947			3,947
Distributions to partners	(73,097		)	—		—			—			(73,097		)
Distributions to noncontrolling interest owners	—			—		—			(9,057		)	(9,057		)
Net changes in advances with consolidated entities	86,638			—		(102,549		)	15,911			—
Other	—			—		(28		)	(70		)	(98		)
Net cash provided by financing activities	13,606			—		111,764			17,701			143,071
Net increase (decrease) in cash and cash equivalents	(6,422		)	—		3,885			4,740			2,203
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	22,693		$	—	$	13,642		$	7,171		$	43,506

(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 June 30, 2015 and March 31, 2015, and for the

Three Months Ended June 30, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Three Months Ended June 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	$	(19,540	)	$	—	$	26,650		$	2,096		$	9,206

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—		(48,608		)	(259		)	(48,867		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(15,619		)	(250		)	(15,869		)
Cash flows from commodity derivatives	—			—		(9,967		)	—			(9,967		)
Proceeds from sales of assets	—			—		989			—			989
Investments in unconsolidated entities	—			—		(4,094		)	—			(4,094		)
Net cash used in investing activities	—			—		(77,299		)	(509		)	(77,808		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facility	—			—		494,500			—			494,500
Payments on revolving credit facility	—			—		(681,000		)	—			(681,000		)
Payments on other long-term debt	—			—		(2,345		)	(2		)	(2,347		)
Debt issuance costs	(576		)	—		(1,618		)	—			(2,194		)
Contributions from general partner	352			—		—			—			352
Distributions to partners	(49,491		)	—		—			—			(49,491		)
Distributions to noncontrolling interest owners	—			—		—			(12		)	(12		)
Proceeds from sale of common units, net of offering costs	338,033			—		—			—			338,033
Net changes in advances with consolidated entities	(238,560		)	—		239,973			(1,413		)	—
Net cash provided by (used in) financing activities	49,758			—		49,510			(1,427		)	97,841
Net increase (decrease) in cash and cash equivalents	30,218			—		(1,139		)	160			29,239
Cash and cash equivalents, beginning of period	1,181			—		8,728			531			10,440
Cash and cash equivalents, end of period	$	31,399		$	—	$	7,589		$	691		$	39,679

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 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 our financial condition and results of operations as of and for the three months ended June 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 June 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 contracts whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers.

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 price risk 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 utilize 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 range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at period end were as follows:

	Spot Price Per Barrel
Three Months Ended June 30,	Low		High		At Period End
2015	$	49.14	$	61.43	$	59.47
2014	99.42		107.26		105.37

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 facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado 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 of the customers at our other facilities are not under volume commitments.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 21 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 the impact of 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 attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

Our wholesale liquids business is a “cost-plus” business that can be affected both by 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.

The range of low and high spot propane prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at period end were as follows:

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price Per Gallon						Spot Price Per Gallon
Three Months Ended June 30,	Low		High		At Period End		Low		High		At Period End
2015	$	0.28	$	0.51	$	0.34	$	0.32	$	0.57	$	0.42
2014	0.96		1.13		1.07		0.99		1.13		1.06

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The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows:

	Spot Price Per Gallon
Three Months Ended June 30,	Low		High		At Period End
2015	$	0.46	$	0.68	$	0.57
2014	1.20		1.30		1.30

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 differential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing on price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers. 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.

The range of low and high spot gasoline prices per barrel using NYMEX gasoline prompt-month futures and the prices at period end were as follows:

	Spot Price Per Barrel
Three Months Ended June 30,	Low		High		At Period End
2015	$	73.05	$	90.15	$	87.76
2014	120.41		131.36		129.23

The range of low and high spot diesel prices per barrel using NYMEX ULSD prompt-month futures and the prices at period end were as follows:

	Spot Price Per Barrel
Three Months Ended June 30,	Low		High		At Period End
2015	$	70.67	$	84.68	$	79.24
2014	119.62		128.20		124.77

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Recent Developments

In June 2015, we announced plans to form a joint venture with Meritage Midstream Services II, LLC (“Meritage”) to develop crude oil gathering and water services infrastructure to serve crude oil and natural gas producers in Wyoming’s Powder River Basin. The joint venture will focus on crude oil and wastewater gathering pipelines, pipeline injection terminals, wastewater and solid waste disposal facilities, and fresh water supply. The joint venture plans to have access to and operate on Meritage’s dedicated acreage in the Powder River Basin.

Acquisitions

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

Year Ending March 31, 2016

· 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 three months ended June 30, 2015, we purchased six water treatment and disposal facilities under these development agreements.

· During the three months ended June 30, 2015, we completed an acquisition of a retail propane business that operates in the northeastern United States.

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 U.S. markets and entered into a construction agreement to expand the storage capacity of the facility.

· In November 2014, we completed the acquisition of 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 completed eight acquisitions of retail propane businesses that operate in the northeastern, Midwest, and southern United States.

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

During the three months ended June 30, 2015, we generated an operating loss of $14.7 million, compared to an operating loss of $20.6 million during the three months ended June 30, 2014.

Our crude oil logistics segment generated operating income of $12.0 million during the three months ended June 30, 2015, compared to operating income of $1.5 million during the three months ended June 30, 2014. Crude oil markets were in contango during the three months ended June 30, 2015 (a condition in which forward crude prices are greater than spot prices), and we are better able to utilize our storage assets when crude oil markets are in contango.

Our water solutions segment generated an operating loss of $3.1 million during the three months ended June 30, 2015, compared to an operating loss of $0.9 million during the three months ended June 30, 2014. The acquisition and development of new facilities contributed to operating profit during the three months ended June 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.

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Our liquids segment generated an operating loss of $0.5 million during the three months ended June 30, 2015, compared to an operating loss of $0.9 million during the three months ended June 30, 2014. Due to the seasonal nature of demand for natural gas liquids, sales volumes of our liquids segment are typically lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year. Sawtooth, which we acquired in February 2015, generated $1.0 million of operating income during the three months ended June 30, 2015. In addition, sales volumes and per-gallon product margins for butane and other products were higher during the three months ended June 30, 2015 than during the three months ended June 30, 2014. These increases were offset by a decrease in product margins from sales of propane, which was due primarily to the fact that propane prices decreased during the three months ended June 30, 2015.

Our retail propane segment generated an operating loss of $0.7 million during the three months ended June 30, 2015, compared to an operating loss of $1.6 million during the three months ended June 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 operating loss during the three months ended June 30, 2015 compared to the three months ended June 30, 2014 was increased margins on propane sales.

Our refined products and renewables segment generated operating income of $33.0 million during the three months ended June 30, 2015, compared to an operating loss of $1.3 million during the three months ended June 30, 2014. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne.

We recorded $8.7 million of earnings from our equity method investments during the three months ended June 30, 2015, compared to $2.6 million of earnings from our equity method investments during the three months ended June 30, 2014. The increase is due primarily to the fact that we acquired two equity method investments as part of our July 2014 acquisition of TransMontaigne.

We incurred interest expense of $30.8 million during the three months ended June 30, 2015, compared to interest expense of $20.5 million during the three months ended June 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 June 30,
	2015			2014
	(in thousands)
Total revenues	$	3,538,469		$	3,648,614
Total cost of sales	3,322,551			3,534,053
Operating expenses	107,914			67,436
General and administrative expenses	62,481			27,873
Depreciation and amortization	59,831			39,375
Loss on disposal or impairment of assets, net	421			432
Operating loss	(14,729		)	(20,555		)
Equity in earnings of unconsolidated entities	8,718			2,565
Interest expense	(30,802		)	(20,494		)
Other expense, net	(1,175		)	(391		)
Loss before income taxes	(37,988		)	(38,875		)
Income tax provision	(538		)	(1,035		)
Net loss	(38,526		)	(39,910		)
Less: Net income allocated to general partner	(15,359		)	(9,381		)
Less: Net income attributable to noncontrolling interests	(3,875		)	(65		)
Net loss allocated to limited partners	$	(57,760	)	$	(49,356	)

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 have had a significant impact on the comparability of our results of operations during the three months ended June 30, 2015 and 2014.

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Non-GAAP Financial Measures

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

	Three Months Ended June 30,
	2015			2014
	(in thousands)
Net loss attributable to parent equity	$	(42,401	)	$	(39,975	)
Interest expense	28,648			20,517
Income tax provision	521			1,035
Depreciation and amortization	54,168			44,350
EBITDA	40,936			25,927
Net unrealized losses on derivatives	3,540			5,010
Inventory valuation adjustment	10,158			—
Lower of cost or market adjustments	(6,340		)	—
Loss on disposal or impairment of assets, net	419			458
Equity-based compensation expense (1)	40,232			7,914
Adjusted EBITDA	$	88,945		$	39,309

(1) This amount includes $3.9 million of expense associated with accrued bonuses that were paid in common units subsequent to June 30, 2015. As a result, the amount in this table for the three months ended June 30, 2015 is greater than the amount of equity-based compensation reported in Note 11 to our condensed consolidated financial statements included in this Quarterly Report on Form 10—Q (“Quarterly Report”).

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, gain (loss) on disposal or impairment of assets, net, 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 accounting principles generally accepted in the United States (“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 and 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 above 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.

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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:

	Three Months Ended June 30,
	2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	54,168		$	44,350
Intangible asset amortization recorded to cost of sales	(1,701		)	(2,137		)
Depreciation and amortization of unconsolidated entities	(5,034		)	(2,945		)
Depreciation and amortization attributable to noncontrolling interests	12,398			107
Depreciation and amortization per condensed consolidated statements of operations	$	59,831		$	39,375

	Three Months Ended June 30,
	2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	54,168		$	44,350
Amortization of debt issuance costs recorded to interest expense	2,282			1,912
Depreciation and amortization of unconsolidated entities	(5,034		)	(2,945		)
Depreciation and amortization attributable to noncontrolling interests	12,398			107
Depreciation and amortization per condensed consolidated statements of cash flows	$	63,814		$	43,424

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

	Three Months Ended June 30,
	2015			2014
	(in thousands)
Interest expense per EBITDA table	$	28,648		$	20,517
Interest expense of unconsolidated entities	(95		)	(23		)
Gain on extinguishment of debt of unconsolidated entities	693			—
Interest expense attributable to noncontrolling interests	1,556			—
Interest expense per condensed consolidated statements of operations	$	30,802		$	20,494

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
Three Months Ended June 30,	Expansion		Maintenance		Total
	(in thousands)
2015	$	113,113	$	10,554	$	123,667
2014	42,405		6,462		48,867

Of the maintenance capital during the three months ended June 30, 2015, $2.9 million related to TLP.

Segment Operating Results for the Three Months Ended June 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 was 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 three months ended June 30, 2015 are not necessarily indicative of the results 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 delivered during the three months ended June 30, 2015 and 2014. Volumes shown in the following table include intersegment sales.

	Three Months Ended June 30,
Segment	2015	2014	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	23,683	19,257	4,426

Water solutions
Water delivered (barrels)	54,476	27,438	27,038

Liquids
Propane sold (gallons)	227,952	183,758	44,194
Other products sold (gallons)	191,987	186,725	5,262

Retail propane
Propane sold (gallons)	24,407	23,591	816
Distillates sold (gallons)	5,093	5,278	(185	)

Refined products and renewables
Refined products sold (barrels)	20,927	7,900	13,027
Renewable products sold (barrels)	1,375	1,263	112

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 June 30,
	2015									2014
				Cost of			Product						Cost of			Product
	Revenues			Sales			Margin			Revenues			Sales			Margin
	(in thousands)
Crude oil logistics	$	1,331,732		$	1,295,940		$	35,792		$	1,939,058		$	1,907,414		$	31,644
Water solutions	54,293			3,607			50,686			47,314			10,573			36,741
Liquids	262,501			245,792			16,709			516,521			503,350			13,171
Retail propane	64,447			29,564			34,883			77,902			47,524			30,378
Refined products and renewables	1,843,175			1,765,313			77,862			1,117,497			1,114,313			3,184
Corporate and other	—			—			—			1,461			1,988			(527		)
Eliminations	(17,679		)	(17,665		)	(14		)	(51,139		)	(51,109		)	(30		)
Total	$	3,538,469		$	3,322,551		$	215,918		$	3,648,614		$	3,534,053		$	114,561

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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 June 30,
Segment	2015			2014			Change
	(in thousands)
Crude oil logistics	$	11,960		$	1,463		$	10,497
Water solutions	(3,072		)	(907		)	(2,165		)
Liquids	(471		)	(913		)	442
Retail propane	(700		)	(1,586		)	886
Refined products and renewables	33,020			(1,255		)	34,275
Corporate and other	(55,466		)	(17,357		)	(38,109		)
Operating loss	$	(14,729	)	$	(20,555	)	$	5,826

Crude Oil Logistics

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

	Three Months Ended June 30,
	2015		2014		Change
	(in thousands)
Revenues:
Crude oil sales	$	1,312,783	$	1,929,055	$	(616,272	)
Crude oil transportation and other	18,949		10,003		8,946
Total revenues (1)	1,331,732		1,939,058		(607,326		)
Expenses:
Cost of sales	1,295,940		1,907,414		(611,474		)
Operating expenses	11,750		15,985		(4,235		)
General and administrative expenses	2,080		4,465		(2,385		)
Depreciation and amortization expense	10,002		9,731		271
Total expenses	1,319,772		1,937,595		(617,823		)
Segment operating income	$	11,960	$	1,463	$	10,497

(1) Revenues include $3.9 million and $9.8 million of intersegment sales during the three months ended June 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $1.3 billion of revenue from crude oil sales during the three months ended June 30, 2015, selling 23.7 million barrels at an average price of $55.43 per barrel. During the three months ended June 30, 2014, our crude oil logistics segment generated $1.9 billion of revenue from crude oil sales, selling 19.3 million barrels at an average price of $100.17 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices subsequent to June 30, 2014. The increase in our sales volumes was due to expanded operations.

Crude oil transportation and other revenues were $18.9 million during the three months ended June 30, 2015, compared to $10.0 million of crude oil transportation and other revenues during the three months ended June 30, 2014. The increase is due primarily to the fact that crude oil markets were in contango during the three months ended June 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 $1.3 billion during the three months ended June 30, 2015, as we sold 23.7 million barrels at an average cost of $54.72 per barrel. Our cost of sales during the three months ended June 30, 2015 was reduced by $0.8 million of net unrealized gains on derivatives. During the three months ended June 30, 2014, our cost of crude oil sold was $1.9 billion, as we sold 19.3 million barrels at an average cost of $99.05 per barrel. Our cost of sales during the three months ended June 30, 2014 was

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reduced by $2.4 million of net unrealized gains on derivatives. Our product margins for crude oil sales are summarized below (in thousands, except per barrel amounts):

	Three Months Ended June 30,
	2015			2014
Crude oil sales revenues	$	1,312,783		$	1,929,055
Crude oil cost of sales	(1,295,940		)	(1,907,414		)
Crude oil product margin	$	16,843		$	21,641

Crude oil sold (barrels)	23,683			19,257

Product margin per barrel	$	0.71		$	1.12

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

Operating Expenses. Our crude oil logistics segment incurred $11.8 million of operating expenses during the three months ended June 30, 2015, compared to $16.0 million of operating expenses during the three months ended June 30, 2014. This decrease was due primarily to lower incentive compensation expense, as incentive compensation expense for the three months ended June 30, 2015 is reported within “corporate and other,” rather than within the crude oil logistics segment, and lower repair and maintenance expense due to the timing of repairs.

General and Administrative Expenses. Our crude oil logistics segment incurred $2.1 million of general and administrative expenses during the three months ended June 30, 2015, compared to $4.5 million of general and administrative expenses during the three months ended June 30, 2014. General and administrative expenses during the three months ended June 30, 2014 included $2.1 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.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $10.0 million of depreciation and amortization expense during the three months ended June 30, 2015, compared to $9.7 million of depreciation and amortization expense during the three months ended June 30, 2014.

Water Solutions

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

	Three Months Ended June 30,
	2015			2014			Change
	(in thousands)
Revenues:
Service fees	$	36,738		$	17,701		$	19,037
Recovered hydrocarbons	15,818			24,015			(8,197		)
Water transportation	—			5,598			(5,598		)
Other revenues	1,737			—			1,737
Total revenues	54,293			47,314			6,979
Expenses:
Cost of sales—derivative loss (1)	3,607			7,303			(3,696		)
Cost of sales—other	—			3,270			(3,270		)
Operating expenses	32,194			19,729			12,465
General and administrative expenses	718			827			(109		)
Depreciation and amortization expense	20,846			17,092			3,754
Total expenses	57,365			48,221			9,144
Segment operating loss	$	(3,072	)	$	(907	)	$	(2,165	)

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

The following tables summarize activity separated among the following categories:

· facilities we owned prior to March 31, 2014;

· facilities we developed subsequent to March 31, 2014; and

· facilities we acquired subsequent to March 31, 2014.

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

	Three Months Ended June 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	$	21,313	26,867	$	0.79	$	17,701	27,438	$	0.65
Recently developed facilities	3,458		5,905	0.59		—		—	—
Recently acquired facilities	11,967		21,704	0.55		—		—	—
Total	$	36,738	54,476	0.67		$	17,701	27,438	0.65

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

	Three Months Ended June 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	$	9,794	26,867	$	0.36	$	24,015	27,438	$	0.88
Recently developed facilities	2,044		5,905	0.35		—		—	—
Recently acquired facilities	3,980		21,704	0.18		—		—	—
Total	$	15,818	54,476	0.29		$	24,015	27,438	0.88

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

Our water solutions segment generated no water transportation revenue during the three months ended June 30, 2015, compared to $5.6 million of water transportation revenue during the three months ended June 30, 2014. The decrease resulted from the sale of our water transportation business 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 was increased by $1.7 million of net unrealized losses on derivatives and $1.9 million of net realized losses on derivatives during the three months ended June 30, 2015.

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Our cost of sales was increased by $6.2 million of net unrealized losses on derivatives and $1.1 million of net realized losses on derivatives during the three months ended June 30, 2014.

We had no other cost of sales during the three months ended June 30, 2015, compared to $3.3 million during the three months ended June 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 June 30,
	2015		2014		Change
	(in thousands)
Existing facilities	$	19,460	$	19,729	$	(269	)
Recently developed facilities	2,160		—		2,160
Recently acquired facilities	10,574		—		10,574
Total	$	32,194	$	19,729	$	12,465

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

Depreciation and Amortization Expense. Our water solutions segment incurred $20.8 million of depreciation and amortization expense during the three months ended June 30, 2015, compared to $17.1 million of depreciation and amortization expense during the three months ended June 30, 2014. Of this increase, $3.4 million related to acquisitions.

Liquids

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

	Three Months Ended June 30,
	2015			2014			Change
	(in thousands)
Revenues:
Propane sales	$	105,162		$	222,446		$	(117,284	)
Other product sales	147,589			288,359			(140,770		)
Other revenues	9,750			5,716			4,034
Total revenues (1)	262,501			516,521			(254,020		)
Expenses:
Cost of sales—propane	105,805			218,907			(113,102		)
Cost of sales—other products	137,409			281,262			(143,853		)
Cost of sales—other	2,578			3,181			(603		)
Operating expenses	9,971			9,065			906
General and administrative expenses	2,205			1,818			387
Depreciation and amortization expense	5,004			3,201			1,803
Total expenses	262,972			517,434			(254,462		)
Segment operating loss	$	(471	)	$	(913	)	$	442

(1) Revenues include $13.5 million and $41.3 million of intersegment sales during the three months ended June 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our liquids segment generated $105.2 million of wholesale propane sales revenue during the three months ended June 30, 2015, selling 228.0 million gallons at an average price of $0.46 per gallon. During the three months ended June 30, 2014, our liquids segment generated $222.4 million of wholesale propane sales revenue, selling 183.8 million gallons at an average price of $1.21 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.

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Our liquids segment generated $147.6 million of other wholesale products sales revenue during the three months ended June 30, 2015, selling 192.0 million gallons at an average price of $0.77 per gallon. During the three months ended June 30, 2014, our liquids segment generated $288.4 million of other wholesale products sales revenue, selling 186.7 million gallons at an average price of $1.54 per gallon. The increase in the volume of other wholesale products sold was due primarily to a new agreement under which we market the majority of the production from a fractionation facility and to the expansion of another such agreement.

Our liquids segment generated $9.8 million of other revenues during the three months ended June 30, 2015, compared to $5.7 million of other revenues during the three months ended June 30, 2014. This revenue includes storage sublease income, and income generated from the operation of a terminal for a customer. This increase was due primarily to $4.8 million of revenue related to Sawtooth, which we acquired in February 2015.

Cost of Sales. Our cost of wholesale propane sales was $105.8 million during the three months ended June 30, 2015, as we sold 228.0 million gallons at an average cost of $0.46 per gallon. Our cost of wholesale propane sales during the three months ended June 30, 2015 was increased by $1.0 million of net unrealized losses on derivatives. During the three months ended June 30, 2014, our cost of wholesale propane sales was $218.9 million, as we sold 183.8 million gallons at an average cost of $1.19 per gallon. Our cost of wholesale propane sales during the three months ended June 30, 2014 was reduced by $0.2 million of net unrealized gains on derivatives. Our product margins for propane sales are summarized below (in thousands, except per gallon amounts):

	Three Months Ended June 30,
	2015			2014
Propane revenues	$	105,162		$	222,446
Propane cost of sales	(105,805		)	(218,907		)
Propane product margin (loss)	$	(643	)	$	3,539

Propane sold (gallons)	227,952			183,758

Product margin (loss) per gallon	$	0.00		$	0.02

Product margins per gallon of propane sold were lower during the three months ended June 30, 2015 than during the three months ended June 30, 2014. Propane prices decreased during the three months ended June 30, 2015. Our product margins are typically lower during periods of falling prices, due to the delay between when we purchase product and when we sell it. We utilize forward contracts and financial derivatives to hedge a portion, but not all, of the price risk associated with holding inventory. In addition, cost of sales during the three months ended June 30, 2015 was increased by $1.0 million of net unrealized losses on derivatives, compared to cost of sales being reduced by $0.2 million of net unrealized gains on derivatives during the three months ended June 30, 2014.

Our cost of sales of other products was $137.4 million during the three months ended June 30, 2015, as we sold 192.0 million gallons at an average cost of $0.72 per gallon. Our cost of sales of other products during the three months ended June 30, 2015 was increased by $1.6 million of net unrealized losses on derivatives. During the three months ended June 30, 2014, our cost of sales of other products was $281.3 million, as we sold 186.7 million gallons at an average cost of $1.51 per gallon. Our cost of sales of other products during the three months ended June 30, 2014 was increased by $1.5 million of net unrealized losses on derivatives. Our per-gallon product margins during the three months ended June 30, 2015 were similar to those during the three months ended June 30, 2014, as summarized below (in thousands, except per gallon amounts):

	Three Months Ended June 30,
	2015			2014
Other products revenues	$	147,589		$	288,359
Other products cost of sales	(137,409		)	(281,262		)
Other products product margin	$	10,180		$	7,097

Other products sold (gallons)	191,987			186,725

Product margin per gallon	$	0.05		$	0.04

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Operating Expenses. Our liquids segment incurred $10.0 million of operating expenses during the three months ended June 30, 2015, compared to $9.1 million of operating expenses during the three months ended June 30, 2014. This increase was due primarily to the acquisition of Sawtooth.

General and Administrative Expenses. Our liquids segment incurred $2.2 million of general and administrative expenses during the three months ended June 30, 2015, compared to $1.8 million of general and administrative expenses during the three months ended June 30, 2014. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $5.0 million of depreciation and amortization expense during the three months ended June 30, 2015, compared to $3.2 million of depreciation and amortization expense during the three months ended June 30, 2014. This increase was due to $2.4 million of depreciation and amortization expense associated with Sawtooth.

Retail Propane

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

	Three Months Ended June 30,
	2015			2014			Change
	(in thousands)
Revenues:
Propane sales	$	43,185		$	52,026		$	(8,841	)
Distillate sales	12,947			18,695			(5,748		)
Other revenues	8,315			7,181			1,134
Total revenues	64,447			77,902			(13,455		)
Expenses:
Cost of sales—propane	16,311			29,287			(12,976		)
Cost of sales—distillates	10,192			16,036			(5,844		)
Cost of sales—other	3,061			2,201			860
Operating expenses	23,771			21,482			2,289
General and administrative expenses	3,106			2,911			195
Depreciation and amortization expense	8,706			7,571			1,135
Total expenses	65,147			79,488			(14,341		)
Segment operating loss	$	(700	)	$	(1,586	)	$	886

Revenues. Our retail propane segment generated revenue of $43.2 million from propane sales during the three months ended June 30, 2015, selling 24.4 million gallons at an average price of $1.77 per gallon. During the three months ended June 30, 2014, our retail propane segment generated $52.0 million of revenue from propane sales, selling 23.6 million gallons at an average price of $2.21 per gallon. The increase in volume sold was due in part to the growth of our business through acquisitions. Sales volumes benefitted from cold weather conditions in the northeast during the recent winter heating season.

Our retail propane segment generated revenue of $12.9 million from distillate sales during the three months ended June 30, 2015, selling 5.1 million gallons at an average price of $2.54 per gallon. During the three months ended June 30, 2014, our retail propane segment generated $18.7 million of revenue from distillate sales, selling 5.3 million gallons at an average price of $3.54 per gallon.

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Cost of Sales. Our cost of retail propane sales was $16.3 million during the three months ended June 30, 2015, as we sold 24.4 million gallons at an average cost of $0.67 per gallon. During the three months ended June 30, 2014, our cost of retail propane sales was $29.3 million, as we sold 23.6 million gallons at an average cost of $1.24 per gallon. Our product margins for propane sales are summarized below (in thousands, except per gallon amounts):

	Three Months Ended June 30,
	2015			2014
Propane revenues	$	43,185		$	52,026
Propane cost of sales	(16,311		)	(29,287		)
Propane product margin	$	26,874		$	22,739

Propane sold (gallons)	24,407			23,591

Product margin per gallon	$	1.10		$	0.96

Our cost of distillate sales was $10.2 million during the three months ended June 30, 2015, as we sold 5.1 million gallons at an average cost of $2.00 per gallon. During the three months ended June 30, 2014, our cost of distillate sales was $16.0 million, as we sold 5.3 million gallons at an average cost of $3.04 per gallon. Our product margins for distillate sales are summarized below (in thousands, except per gallon amounts):

	Three Months Ended June 30,
	2015			2014
Distillate revenues	$	12,947		$	18,695
Distillate cost of sales	(10,192		)	(16,036		)
Distillate product margin	$	2,755		$	2,659

Distillate sold (gallons)	5,093			5,278

Product margin per gallon	$	0.54		$	0.50

Operating Expenses. Our retail propane segment incurred $23.8 million of operating expenses during the three months ended June 30, 2015, compared to $21.5 million of operating expenses during the three months ended June 30, 2014. The increase was due primarily to increased compensation expense resulting from the growth of the business.

General and Administrative Expenses. Our retail propane segment incurred $3.1 million of general and administrative expenses during the three months ended June 30, 2015, compared to $2.9 million of general and administrative expenses during the three months ended June 30, 2014.

Depreciation and Amortization Expense. Our retail propane segment incurred $8.7 million of depreciation and amortization expense during the three months ended June 30, 2015, compared to $7.6 million of depreciation and amortization expense during the three months ended June 30, 2014.

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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 partially offset by a sharp decline in product prices during the year ended March 31, 2015.

	Three Months Ended June 30,
	2015		2014			Change
	(in thousands)
Revenues:
Refined products sales (1)	$	1,708,949	$	986,223		$	722,726
Renewables sales	106,153		131,274			(25,121		)
Service fees	28,073		—			28,073
Total revenues	1,843,175		1,117,497			725,678
Expenses:
Cost of sales—refined products	1,659,497		983,012			676,485
Cost of sales—renewables	105,816		131,301			(25,485		)
Operating expenses	25,863		1,624			24,239
General and administrative expenses	4,804		1,971			2,833
Depreciation and amortization expense	14,175		844			13,331
Total expenses	1,810,155		1,118,752			691,403
Segment operating income (loss)	$	33,020	$	(1,255	)	$	34,275

(1) Revenues include $0.2 million of intersegment sales during the three months ended June 30, 2015 that are eliminated in our condensed consolidated statement of operations.

Revenues. Our refined products sales revenue was $1.7 billion during the three months ended June 30, 2015, selling 20.9 million barrels at an average price of $81.66 per barrel. Our refined products sales revenue was $986.2 million during the three months ended June 30, 2014, selling 7.9 million barrels at an average price of $124.84 per barrel.

Our renewables sales revenue was $106.2 million during the three months ended June 30, 2015, selling 1.4 million barrels at an average price of $77.20 per barrel. Our renewables sales revenue was $131.3 million during the three months ended June 30, 2014, selling 1.3 million barrels at an average price of $103.94 per barrel.

Our refined products and renewables segment generated $28.1 million of service fee revenue during the three months ended June 30, 2015, which was due primarily to TLP’s refined products terminaling operations.

Cost of Sales. Our cost of refined products sales was $1.7 billion during the three months ended June 30, 2015, as we sold 20.9 million barrels at an average cost of $79.30 per barrel. Our cost of sales during the three months ended June 30, 2015 was increased by $24.9 million of net losses on derivatives. Our cost of refined products sales was $983.0 million during the three months ended June 30, 2014, as we sold 7.9 million barrels at an average cost of $124.43 per barrel. Our refined product margins are summarized below (in thousands, except per barrel and per gallon amounts):

	Three Months Ended June 30,
	2015			2014
Revenues	$	1,708,949		$	986,223
Cost of sales	(1,659,497		)	(983,012		)
Product margin	$	49,452		$	3,211

Refined products sold (barrels)	20,927			7,900

Product margin per barrel	$	2.36		$	0.41
Product margin per gallon	$	0.06		$	0.01

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Our cost of renewables sales was $105.8 million during the three months ended June 30, 2015, as we sold 1.4 million barrels at an average cost of $76.95 per barrel. Our cost of renewables sales was $131.3 million during the three months ended June 30, 2014, as we sold 1.3 million barrels at an average cost of $103.96 per barrel. Our renewables product margins are summarized below (in thousands, except per barrel amounts):

	Three Months Ended June 30,
	2015			2014
Revenues	$	106,153		$	131,274
Cost of sales	(105,816		)	(131,301		)
Product margin (loss)	$	337		$	(27	)

Renewables sold (barrels)	1,375			1,263

Product margin (loss) per barrel	$	0.25		$	(0.02	)

Operating and General and Administrative Expenses. Our refined products and renewables segment incurred $25.9 million of operating expenses during the three months ended June 30, 2015, compared to $1.6 million of operating expenses during the three months ended June 30, 2014. Our refined products and renewables segment incurred $4.8 million of general and administrative expenses during the three months ended June 30, 2015, compared to $2.0 million of general and administrative expenses during the three months ended June 30, 2014. Of the operating and general and administrative expenses during the three months ended June 30, 2015, $20.6 million was attributable to TLP.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $14.2 million of depreciation and amortization expense during the three months ended June 30, 2015, compared to $0.8 million of depreciation and amortization expense during the three months ended June 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 during the three months ended June 30, 2015, $13.3 million was attributable to TLP.

Corporate and Other

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

	Three Months Ended June 30,
	2015			2014			Change
	(in thousands)
Equity-based compensation expense	$	(36,294	)	$	(7,914	)	$	(28,380	)
Acquisition expenses	(65		)	(1,098		)	1,033
Other corporate expenses	(19,107		)	(8,345		)	(10,762		)
Total	$	(55,466	)	$	(17,357	)	$	(38,109	)

The increase in equity-based compensation expense was due to several factors. As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors (the “Compensation Committee”) 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 three months ended June 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 $17.8 million of expense related to the Performance Awards during the three months ended June 30, 2015, $15.5 million of which related to the July 1, 2015 vesting tranche.

In addition, the number of outstanding awards for which the vesting is contingent only on the continued service of the recipients (the “Service Awards”) was higher at June 30, 2015 than at June 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 Award units granted to certain employees following the Compensation Committee’s review of our compensation program. Certain of the Service Award units granted during the three months ended June 30, 2015 vested on July 1, 2015, and we recorded $3.3 million of expense related to Service Awards that were granted during the three months ended June 30, 2015.

The increase in other corporate expenses during the three months ended June 30, 2015 was due in part to $3.9 million of expense associated with certain bonuses that we expect to pay in common units, and therefore were recorded to “corporate and other” rather than to the operating segments. In addition, other corporate expenses for the three months ended June 30, 2015 includes $5.9 million associated with estimated bonuses for performance during fiscal year 2016. Since the allocation of the bonuses among the operating segments will be influenced by the performance of each segment over the full fiscal year, we do not plan to attribute this expense to the operating segments until the end of the fiscal year.

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $8.7 million during the three months ended June 30, 2015, compared to equity in earnings of unconsolidated entities of $2.6 million during the three months ended June 30, 2014. The increase is due primarily to the fact that we acquired two equity method investments as part of our July 2014 acquisition of TransMontaigne.

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Interest Expense

Interest expense includes interest expense on our revolving credit facilities and senior note issuances, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations assumed in business combinations. Interest expense was $30.8 million during the three months ended June 30, 2015, compared to interest expense of $20.5 million during the three months ended June 30, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (hereinafter defined) to finance acquisitions and capital expenditures, debt outstanding on the TLP Credit Facility (hereinafter defined) associated with the July 2014 acquisition of TransMontaigne, and the issuance of the 2019 Notes (hereinafter defined) in July 2014.

Income Tax Provision

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 2011 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize 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 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 expense was $0.5 million during the three months ended June 30, 2015, compared to income tax expense of $1.0 million during the three months ended June 30, 2014.

Noncontrolling Interests

Net income attributable to noncontrolling interests was $3.9 million during the three months ended June 30, 2015, compared to net income attributable to noncontrolling interests of $0.1 million during the three months ended June 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 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

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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.

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.

Long-Term Debt

Credit Agreement

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At June 30, 2015, the majority of the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at June 30, 2015 of 2.19%, calculated as the LIBOR rate of 0.19% plus a margin of 2.0%. At June 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.

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

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2019 Notes

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

2021 Notes

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

2022 Notes

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(vii) consolidate or 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.

At June 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 and (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 Battleground Oil Specialty Terminal Company LLC (“BOSTCO”). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date of July 31, 2018.

Cash and cash equivalents	$	5,046
Accounts receivable—trade	7,402
Accounts receivable—affiliates	557
Inventories	1,404
Prepaid expenses and other current assets	975
Property, plant and equipment, net	478,450
Goodwill	30,169
Intangible assets, net	61,600
Investments in unconsolidated entities	256,585
Other noncurrent assets	2,546
Accounts payable—trade	(5,290		)
Accounts payable—affiliates	(118		)
Net intercompany payable	(2,258		)
Accrued expenses and other payables	(6,151		)
Advanced payments received from customers	(152		)
Long-term debt	(257,000		)
Other noncurrent liabilities	(3,301		)
Net assets	$	570,464

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TLP’s Credit Facility is non-recourse to NGL.

Revolving Credit Balances

The following table summarizes our revolving credit facility borrowings:

	Average
	Balance		Lowest		Highest
	Outstanding		Balance		Balance
	(in thousands)
Three Months Ended June 30, 2015:
Expansion capital borrowings	$	818,676	$	739,500	$	890,000
Working capital borrowings	664,841		582,500		738,000
TLP credit facility borrowings	250,108		249,000		261,200

Three Months Ended June 30, 2014:
Expansion capital borrowings	$	529,038	$	270,000	$	578,500
Working capital borrowings	418,973		339,500		500,500

Cash Flows

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

	Three Months Ended June 30,
Cash Flows Provided by (Used in):	2015			2014
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	101,743		$	27,078
Changes in operating assets and liabilities	(19,914		)	(17,872		)

Operating activities	$	81,829		$	9,206

Investing activities	(222,697		)	(77,808		)

Financing activities	143,071			97,841

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail propane and wholesale natural gas liquids businesses also have a significant impact 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.

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Investing Activities. Net cash used in investing activities was $222.7 million during the three months ended June 30, 2015, compared to $77.8 million of net cash used in investing activities during the three months ended June 30, 2014. The increase in net cash used in investing activities was due primarily to:

· an increase in capital expenditures from $48.9 million during the three months ended June 30, 2014, $42.4 million of which was expansion capital and $6.5 million of which was maintenance capital, to $122.1 million during the three months ended June 30, 2015, $111.5 million of which was expansion capital and $10.6 million of which was maintenance capital (of this maintenance capital, $2.9 million related to TLP);

· a $48.0 million increase in cash paid for acquisitions during the three months ended June 30, 2015;

· a $15.6 million increase related to a loan receivable from one of our equity method investees; and

· an $11.7 million increase in cash flows from derivatives.

Financing Activities. Net cash provided by financing activities was $143.1 million during the three months ended June 30, 2015, compared to $97.8 million in net cash provided by financing activities during the three months ended June 30, 2014. The increase in net cash provided by financing activities was due primarily to a $409.5 million increase in borrowings on our revolving credit facilities (net of repayments). This increase in net cash provided by financing activities was partially offset by:

· a $338.0 million decrease in proceeds received from the sale of our common units; and

· a $32.7 million increase in distributions paid to our partners and noncontrolling interest owners.

The following table summarizes the distributions declared subsequent to 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

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The following table summarizes the distributions declared by TLP subsequent to 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

General Partner

(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

Contractual Obligations

The following table summarizes our contractual obligations at June 30, 2015 for our fiscal years ending thereafter:

			Nine 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	$	890,000	$	—	$	—	$	—	$	890,000	$	—	$	—
Working capital borrowings	716,500		—		—		—		716,500		—		—
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	257,000		—		—		—		257,000		—		—
Other long-term debt	8,502		3,908		2,729		1,014		479		249		123
Interest payments on long-term debt —
Revolving Credit Facility (1)	135,509		30,381		40,434		40,434		24,260		—		—
2019 Notes	92,250		20,500		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	78,969		12,469		16,625		16,209		13,300		9,975		10,391
TLP Credit Facility	23,235		5,658		7,530		7,530		2,517		—		—
Other long-term debt	562		205		167		112		45		24		9
Letters of credit	129,873		—		—		—		129,873		—		—
Future minimum lease payments under noncancelable operating leases	530,162		98,704		104,877		89,227		64,815		54,971		117,568
Future minimum throughput payments under noncancelable agreements (2)	482,155		92,499		81,935		82,016		81,222		53,511		90,972
Construction commitments (3)	620,156		469,890		150,266		—		—		—		—
Fixed-price commodity purchase commitments	42,163		42,163		—		—		—		—		—
Index-price commodity purchase commitments (4)	932,630		930,782		1,848		—		—		—		—
Total contractual obligations	$	6,240,760	$	1,722,628	$	457,849	$	312,980	$	2,281,449	$	609,918	$	855,936

Purchase commitments (thousands):
Natural gas liquids fixed-price (gallons) (5)	66,117		66,117		—		—		—		—		—
Natural gas liquids index-price (gallons) (5)	662,883		659,184		3,699		—		—		—		—
Crude oil index-price (barrels) (5)	11,836		11,836		—		—		—		—		—

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at June 30, 2015. See Note 8 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

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(2) At June 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 June 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.

· 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 U.S. 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.

(4) At June 30, 2015, we had the following purchase commitments (in thousands):

Natural gas liquids index-price		$	324,051
Crude oil index-price		608,579

Index prices are based on a forward price curve at June 30, 2015. A theoretical change of $0.10 per gallon in the underlying commodity price at June 30, 2015 would result in a change of $66.3 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 June 30, 2015 would result in a change of $11.8 million in the value of our index-price crude oil purchase commitments.

(5) At June 30, 2015, we had the following sales contract volumes (in thousands):

Natural gas liquids fixed-price (gallons)		170,769
Natural gas liquids index-price (gallons)		261,661
Crude oil fixed-price (barrels)		2,700
Crude oil index-price (barrels)		9,544

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 $47.60 per barrel at March 31, 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.

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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 utilize 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 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.

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 are in the process of 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.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, transportation, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Pursuant to terminaling service agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we take delivery of the wastewater at our treatment and disposal facilities.

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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.

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 June 30, 2015 includes a liability of $4.6 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense represents 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. At the time 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 represents 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. At the time 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

Storage tanks require a certain minimum amount of product to remain in the tank as long as the tank is in service. This product is known as “tank bottoms.” We report tank bottoms we own in storage facilities we own at historical cost within property,

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plant and equipment on our condensed consolidated balance sheets. The following table summarizes the tank bottoms reported in our condensed consolidated balance sheet at June 30, 2015 (in thousands):

Product	Volume	Book Value
Gasoline (barrels)	219	$	25,585
Crude oil (barrels)	232	19,507
Diesel (barrels)	121	14,753
Renewables (barrels)	41	4,220
Other	504	738
Total		$	64,803

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 June 30, 2015, linefill consisted of 487,104 barrels of crude oil with a book value of $35.1 million.

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 us 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 and transportation contracts, and employee compensation commitments. 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 a reasonable period of time (not to exceed 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”).

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We report unvested units as liabilities in our condensed consolidated balance sheets. When units vest and are issued, we record an increase to equity.

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, as deemed appropriate. The principal counterparties associated with our operations at June 30, 2015 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. As a result, our profitability may be impacted by changes in wholesale prices of crude oil, natural gas liquids, and refined products. When there are sudden and sharp increases in the wholesale cost of these products, we may not be able to pass on these increases to our customers through retail or wholesale prices. Crude oil, natural gas liquids, and refined products are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

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

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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.

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 June 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)	$	(3,645	)
Crude oil (water solutions segment)	(2,765		)
Propane (liquids segment)	1,037
Other products (liquids segment)	(941		)
Refined products (refined products and renewables segment)	(32,015		)
Renewables (refined products and renewables segment)	(1,657		)

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 June 30, 2015. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of June 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 June 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

None.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Exhibit

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 June 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months ended June 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the three months ended June 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the three months ended June 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: August 10, 2015		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: August 10, 2015		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit Number		Exhibit

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 June 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months ended June 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the three months ended June 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the three months ended June 30, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.