NGL Energy Partners LP - Quarter Report: 2017 June (Form 10-Q)

Table of Contents

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, 2017

¨ 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 ¨

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 (§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 ¨

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



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company ¨
Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

At August 1, 2017, there were 121,431,043 common units issued and outstanding.

Table of Contents

TABLE OF CONTENTS



PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2017 and March 31, 2017	3
	Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three months ended June 30, 2017 and 2016	5
	Unaudited Condensed Consolidated Statement of Changes in Equity for the three months ended June 30, 2017	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended June 30, 2017 and 2016	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 4.	Controls and Procedures	65
PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 3.	Defaults Upon Senior Securities	67
Item 4.	Mine Safety Disclosures	67
Item 5.	Other Information	67
Item 6.	Exhibits	68
SIGNATURES		69
INDEX TO EXHIBITS		70

Table of Contents

Forward-Looking Statements

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


•	the prices of crude oil, natural gas liquids, gasoline, diesel, 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, gasoline, diesel, ethanol, and biodiesel;


•	the availability of supply of crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;


•	the level of crude oil and natural gas drilling and production in producing areas where 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 affects the price of ethanol;


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


•	actions taken by foreign oil and gas producing nations;


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


•	the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;


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


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


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


•	the effect of energy conservation efforts on product demand;


•	energy efficiencies and technological trends;


•	governmental regulation and taxation;


•	the effect of legislative and regulatory actions on hydraulic fracturing, wastewater disposal, and the treatment of flowback and produced water;


•	hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;


•	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 renew contracts with key customers;


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


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

Table of Contents


•	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 complete accretive acquisitions, and integrate acquired assets and businesses;


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


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


•	changes in applicable laws and regulations, including tax, environmental, transportation, and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the effect 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;


•	changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets; and


•	other risks and uncertainties, including those discussed under Part II, Item 1A–“Risk Factors.”

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 may be 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 discussed under Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 and under Part II, Item 1A–“Risk Factors” in this Quarterly Report.

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(in Thousands, except unit amounts)



	June 30, 2017			March 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	19,548		$	12,264
Accounts receivable-trade, net of allowance for doubtful accounts of $5,407 and $5,234, respectively	652,729			800,607
Accounts receivable-affiliates	1,552			6,711
Inventories	563,093			561,432
Prepaid expenses and other current assets	96,812			103,193
Total current assets	1,333,734			1,484,207
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $400,857 and $375,594, respectively	1,769,618			1,790,273
GOODWILL	1,451,716			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization of $447,392 and $414,605, respectively	1,130,073			1,163,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	190,948			187,423
LOAN RECEIVABLE-AFFILIATE	3,700			3,200
OTHER NONCURRENT ASSETS	238,926			239,604
Total assets	$	6,118,715		$	6,320,379
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	522,155		$	658,021
Accounts payable-affiliates	1,777			7,918
Accrued expenses and other payables	192,849			207,125
Advance payments received from customers	57,071			35,944
Current maturities of long-term debt	42,793			29,590
Total current liabilities	816,645			938,598
LONG-TERM DEBT, net of debt issuance costs of $31,007 and $33,458, respectively, and current maturities	2,834,325			2,963,483
OTHER NONCURRENT LIABILITIES	176,568			184,534
COMMITMENTS AND CONTINGENCIES (NOTE 9)

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 19,942,169 preferred units issued and outstanding, respectively	67,048			63,890
REDEEMABLE NONCONTROLLING INTEREST	3,251			3,072

EQUITY:
General partner, representing a 0.1% interest, 120,974 and 120,300 notional units, respectively	(50,648		)	(50,529		)
Limited partners, representing a 99.9% interest, 120,853,481 and 120,179,407 common units issued and outstanding, respectively	2,063,467			2,192,413
Class B preferred limited partners, 8,400,000 and 0 preferred units issued and outstanding, respectively	202,977			—
Accumulated other comprehensive loss	(2,203		)	(1,828		)
Noncontrolling interests	7,285			26,746
Total equity	2,220,878			2,166,802
Total liabilities and equity	$	6,118,715		$	6,320,379

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(in Thousands, except unit and per unit amounts)



	Three Months Ended June 30,
	2017			2016
REVENUES:
Crude Oil Logistics	$	504,915		$	425,951
Water Solutions	46,967			35,753
Liquids	277,814			205,049
Retail Propane	67,072			60,387
Refined Products and Renewables	2,884,637			1,994,563
Other	161			267
Total Revenues	3,781,566			2,721,970
COST OF SALES:
Crude Oil Logistics	469,470			405,230
Water Solutions	153			5,201
Liquids	271,074			190,992
Retail Propane	29,636			24,820
Refined Products and Renewables	2,871,702			1,940,087
Other	73			110
Total Cost of Sales	3,642,108			2,566,440
OPERATING COSTS AND EXPENSES:
Operating	76,469			75,172
General and administrative	24,991			41,871
Depreciation and amortization	63,879			48,906
Gain on disposal or impairment of assets, net	(11,214		)	(204,319		)
Operating (Loss) Income	(14,667		)	193,900
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	1,816			394
Revaluation of investments	—			(14,365		)
Interest expense	(49,226		)	(30,438		)
(Loss) gain on early extinguishment of liabilities, net	(3,281		)	29,952
Other income, net	2,110			3,772
(Loss) Income Before Income Taxes	(63,248		)	183,215
INCOME TAX EXPENSE	(459		)	(462		)
Net (Loss) Income	(63,707		)	182,753
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(52		)	(5,833		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS	397			—
NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	(63,362		)	176,920
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(9,684		)	(3,384		)
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	40			(203		)
LESS: REPURCHASE OF WARRANTS	(349		)	—
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(73,355	)	$	173,333
BASIC (LOSS) INCOME PER COMMON UNIT	$	(0.61	)	$	1.66
DILUTED (LOSS) INCOME PER COMMON UNIT	$	(0.61	)	$	1.38
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	120,535,909			104,169,573
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	120,535,909			128,453,733

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income

(in Thousands)



	Three Months Ended June 30,
	2017			2016
Net (loss) income	$	(63,707	)	$	182,753
Other comprehensive loss	(375		)	(152		)
Comprehensive (loss) income	$	(64,082	)	$	182,601

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Three Months Ended June 30, 2017

(in Thousands, except unit amounts)



				Limited Partners
				Class B Preferred			Common				Accumulated Other
	General Partner			Units	Amount		Units	Amount			Comprehensive Loss			Noncontrolling Interests			Total Equity
BALANCES AT MARCH 31, 2017	$	(50,529	)	—	$	—	120,179,407	$	2,192,413		$	(1,828	)	$	26,746		$	2,166,802
Distributions to partners (Note 10)	(80		)	—	—		—	(53,319		)	—			—			(53,399		)
Distributions to noncontrolling interest owners	—			—	—		—	—			—			(2,898		)	(2,898		)
Contributions	—			—	—		—	—			—			23			23
Purchase of noncontrolling interest (Note 4)	—			—	—		—	(6,245		)	—			(16,638		)	(22,883		)
Redemption valuation adjustment (Note 2)	—			—	—		—	(576		)	—			—			(576		)
Repurchase of warrants (Note 10)	—			—	—		—	(10,549		)	—			—			(10,549		)
Equity issued pursuant to incentive compensation plan (Note 10)	1			—	—		66,421	8,294			—			—			8,295
Conversion of warrants (Note 10)	—			—	—		607,653	6			—			—			6
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)	—			—	—		—	(3,235		)	—			—			(3,235		)
Issuance of Class B preferred units (Note 10)	—			8,400,000	202,977		—	—			—			—			202,977
Net (loss) income	(40		)	—	—		—	(63,322		)	—			52			(63,310		)
Other comprehensive loss	—			—	—		—	—			(375		)	—			(375		)
BALANCES AT JUNE 30, 2017	$	(50,648	)	8,400,000	$	202,977	120,853,481	$	2,063,467		$	(2,203	)	$	7,285		$	2,220,878

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(in Thousands)



	Three Months Ended June 30,
	2017			2016
OPERATING ACTIVITIES:
Net (loss) income	$	(63,707	)	$	182,753
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation and amortization, including amortization of debt issuance costs	68,201			53,090
Loss (gain) on early extinguishment or revaluation of liabilities, net	3,281			(29,952		)
Non-cash equity-based compensation expense	8,821			22,337
Gain on disposal or impairment of assets, net	(11,214		)	(204,319		)
Provision for doubtful accounts	519			12
Net adjustments to fair value of commodity derivatives	(36,500		)	59,700
Equity in earnings of unconsolidated entities	(1,816		)	(394		)
Distributions of earnings from unconsolidated entities	1,426			177
Revaluation of investments	—			14,365
Other	3,670			(1,378		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	150,748			(75,403		)
Inventories	(5,739		)	(154,625		)
Other current and noncurrent assets	13,510			(57,692		)
Accounts payable-trade and affiliates	(142,007		)	108,844
Other current and noncurrent liabilities	11,798			11,945
Net cash provided by (used in) operating activities	991			(70,540		)
INVESTING ACTIVITIES:
Capital expenditures	(31,491		)	(140,179		)
Acquisitions, net of cash acquired	(19,897		)	(14,458		)
Cash flows from settlements of commodity derivatives	23,287			(21,535		)
Proceeds from sales of assets	20,135			438
Proceeds from sale of TLP common units	—			112,370
Investments in unconsolidated entities	(5,250		)	—
Distributions of capital from unconsolidated entities	2,115			2,941
Payments on loan for natural gas liquids facility	2,401			2,130
Loan to affiliate	(500		)	(1,000		)
Payments on loan to affiliate	—			655
Payment to terminate development agreement	—			(16,875		)
Net cash used in investing activities	(9,200		)	(75,513		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	299,500			433,500
Payments on Revolving Credit Facility	(344,500		)	(454,500		)
Repurchase of senior secured and senior notes	(74,391		)	(15,129		)
Payments on other long-term debt	(1,327		)	(2,102		)
Debt issuance costs	(2,096		)	(45		)
Contributions from noncontrolling interest owners, net	23			329
Distributions to partners	(53,399		)	(40,696		)
Distributions to noncontrolling interest owners	—			(1,355		)
Proceeds from sale of preferred units, net of offering costs	202,977			235,180
Repurchase of warrants	(10,549		)	—
Payments for settlement and early extinguishment of liabilities	(745		)	(26,374		)
Other	—			(53		)
Net cash provided by financing activities	15,493			128,755
Net increase (decrease) in cash and cash equivalents	7,284			(17,298		)
Cash and cash equivalents, beginning of period	12,264			28,176
Cash and cash equivalents, end of period	$	19,548		$	10,878
Supplemental cash flow information:
Cash interest paid	$	54,335		$	29,187
Income taxes paid (net of income tax refunds)	$	1,247		$	1,684
Supplemental non-cash investing and financing activities:
Accrued capital expenditures	$	1,389		$	6,800

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2017, our operations include:


•	Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.


•	Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.


•	Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.


•	Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.


•	Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.

Note 2—Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. Intercompany transactions and account balances have been eliminated in consolidation. Investments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. We also own an undivided interest in a crude oil pipeline, and include our proportionate share of assets, liabilities, and expenses related to this pipeline in our unaudited condensed consolidated financial statements.

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 (“SEC”). Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2017 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2017 included in our Annual Report on Form 10-K (“Annual Report”) filed with the SEC on May 26, 2017.

These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report. Due to the seasonal nature of certain of our operations and other factors, the results of operations for interim periods are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2018.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Use of Estimates

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

Critical estimates we make in the preparation of our unaudited condensed consolidated financial statements include, among others, determining the fair value of assets and liabilities acquired in business combinations, the collectibility of accounts receivable, the recoverability of inventories, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the impairment of assets, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for environmental matters. 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

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


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

•

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


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

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our unaudited condensed consolidated balance sheets except for certain contracts that qualify for the normal purchase and normal sale election. 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.

We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivative instruments that do not qualify as normal purchases and normal sales (whether cash transactions or

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

non-cash mark-to-market adjustments) are reported within cost of sales in our unaudited condensed consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are 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, or refined and renewables 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.

Revenue Recognition

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Revenues for our Water Solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

The tariffs we charge for our pipeline transportation systems are primarily regulated by the Federal Energy Regulatory Commission. Our tariffs include provisions which allow us to deduct from our customer’s inventory a small percentage of the products our customers transport on our pipeline systems. We refer to these product quantities as pipeline loss allowance. We receive pipeline loss allowances from our customers as consideration for product losses during the transportation of their products on our pipeline systems. Our customers are guaranteed delivery of the amount of their injected volumes, net of pipeline loss allowance, irrespective of what our actual product losses may be during the delivery process.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our unaudited condensed consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and 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, 2017 and 2016 include $0.3 million and $1.2 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

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.

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.

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

consolidated financial statements. We had no material uncertain tax positions that required recognition in our unaudited condensed consolidated financial statements at June 30, 2017 or March 31, 2017.

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. On April 1, 2017, we adopted the new inventory standard, Accounting Standards Update (“ASU”) No. 2015-11. Under this ASU, inventory is to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonable predictable costs of completion, disposal, and transportation. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale Liquids business to our Retail Propane business to sell the inventory in retail markets.

Inventories consist of the following at the dates indicated:



	June 30, 2017		March 31, 2017
	(in thousands)
Crude oil	$	85,715	$	146,857
Natural gas liquids:
Propane	66,108		38,631
Butane	49,706		5,992
Other	6,638		6,035
Refined products:
Gasoline	171,329		193,051
Diesel	123,770		98,237
Renewables:
Ethanol	38,100		42,009
Biodiesel	12,447		21,410
Other	9,280		9,210
Total	$	563,093	$	561,432

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. Investments in partnerships and limited liability companies, unless our investment is considered to be minor, and investments in unincorporated joint ventures are also accounted for using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our unaudited condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our unaudited 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. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our unaudited condensed consolidated statements of cash flows.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



Entity	Segment	Ownership Interest (1)	Date Acquired or Formed	June 30, 2017		March 31, 2017
				(in thousands)
Glass Mountain Pipeline, LLC (2)	Crude Oil Logistics	50%	December 2013	$	175,215	$	172,098
E Energy Adams, LLC	Refined Products and Renewables	19%	December 2013	13,445		12,952
Water treatment and disposal facility (3)	Water Solutions	50%	August 2015	2,165		2,147
Victory Propane, LLC	Retail Propane	50%	April 2015	123		226
Total				$	190,948	$	187,423


(1)	Ownership interest percentages are at June 30, 2017.

(2)

Our investment in Glass Mountain Pipeline, LLC (“Glass Mountain”) exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $72.0 million at June 30, 2017. This difference relates primarily to goodwill and customer relationships. We amortize the value of the customer relationships and record the expense within equity in earnings of unconsolidated entities in our unaudited condensed consolidated statement of operations.


(3)	This is an investment in an unincorporated joint venture.

Other Noncurrent Assets

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



	June 30, 2017		March 31, 2017
	(in thousands)
Loan receivable (1)	$	38,004	$	40,684
Line fill (2)	30,628		30,628
Tank bottoms (3)	42,044		42,044
Minimum shipping fees - pipeline commitments (4)	71,048		67,996
Other	57,202		58,252
Total	$	238,926	$	239,604


(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, 2017 and March 31, 2017, line fill consisted of 427,193 barrels and 427,193 barrels of crude oil, respectively. Line fill held in pipelines we own is included within property, plant and equipment (see Note 5).

(3)

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At June 30, 2017 and March 31, 2017, tank bottoms held in third party terminals consisted of 366,212 barrels and 366,212 barrels of refined products, respectively. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).


(4)	Represents the minimum shipping fees paid in excess of volumes shipped. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 9).

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Accrued Expenses and Other Payables

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



	June 30, 2017		March 31, 2017
	(in thousands)
Accrued compensation and benefits	$	18,337	$	22,227
Excise and other tax liabilities	61,284		64,051
Derivative liabilities	23,428		27,622
Accrued interest	36,454		44,418
Product exchange liabilities	8,844		1,693
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	14,389		17,001
Total	$	192,849	$	207,125

Deferred Gain on Sale of General Partner Interest in TLP

On February 1, 2016, we sold our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners. We deferred a portion of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended June 30, 2017 and 2016, we recognized $7.5 million and $7.5 million, respectively, of the deferred gain in our unaudited condensed consolidated statements of operations. Within our unaudited condensed consolidated balance sheet, the current portion of the deferred gain, $30.1 million, is recorded in accrued expenses and other payables and the long-term portion, $131.8 million, is recorded in other noncurrent liabilities.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrolling interests are reported as a component of equity, unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in our unaudited condensed consolidated balance sheet. The redeemable noncontrolling interest is adjusted at the balance sheet date to its maximum redemption value if the amount is greater than the carrying value. During the three months ended June 30, 2017, we recorded $0.6 million to adjust the redeemable noncontrolling interest to its maximum redemption value.

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 value of the assets acquired and liabilities assumed in a business combination. As discussed in Note 4, certain of our acquisitions are still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change.

Reclassifications

We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows. Also, certain line items in our unaudited condensed consolidated statement of cash flows were combined and the prior period amounts were combined to be consistent with the classification methods used in the current fiscal year.

Recent Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-15, “Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments.” The ASU requires cash payments not made soon after the

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

acquisition date of a business combination by an acquirer to settle a contingent consideration liability to be separated and classified as cash outflows for financing activities and operating activities. Cash payments up to the amount of the contingent consideration liability recognized at the acquisition date (including measurement-period adjustments) should be classified as financing activities and any excess should be classified as operating activities. We adopted this ASU effective April 1, 2017 and have revised previously reported information.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses.” The ASU requires a financial asset (or a group of financial assets) measured at amortized cost to be presented at the net amount expected to be collected, which would include accounts receivable. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. The ASU is effective for the Partnership beginning April 1, 2020, and requires a modified retrospective method of adoption, although early adoption is permitted. We are currently in the process of assessing the impact of this ASU on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” The ASU will replace previous lease accounting guidance in GAAP. The ASU requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The ASU retains a distinction between finance leases and operating leases. The ASU is effective for the Partnership beginning April 1, 2019, and requires a modified retrospective method of adoption. We are currently in the process of compiling a database of leases and analyzing each lease to assess the impact under this ASU on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The ASU 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 methods of adoption.

We are in the process of evaluating our revenue contracts by segment and type to determine the potential impact of adopting this ASU. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of this ASU; however, we are still in the process of quantifying these impacts and have not yet determined whether they would be material to our consolidated financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under this ASU. We continue to monitor additional authoritative or interpretive guidance related to this ASU as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us. We currently anticipate utilizing a modified retrospective adoption as of April 1, 2018.

Note 3—Income (Loss) Per Common Unit

The following table presents our calculation of basic and diluted weighted average units outstanding for the periods indicated:



	Three Months Ended June 30,
	2017	2016
Weighted average units outstanding during the period:
Common units - Basic	120,535,909	104,169,573
Effect of Dilutive Securities:
Warrants	—	4,341,991
Class A Preferred Units	—	19,942,169
Common units - Diluted	120,535,909	128,453,733

For the three months ended June 30, 2017, Class A Preferred Units (as defined herein), warrants, Performance Awards (as defined herein), and Service Awards (as defined herein) were considered antidilutive. For the three months ended June 30, 2016, the Service Awards and Performance Awards were considered antidilutive.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



	Three Months Ended June 30,
	2017			2016
	(in thousands, except unit and per unit amounts)
Net (loss) income	$	(63,707	)	$	182,753
Less: Net income attributable to noncontrolling interests	(52		)	(5,833		)
Less: Net loss attributable to redeemable noncontrolling interests	397			—
Net (loss) income attributable to NGL Energy Partners LP	(63,362		)	176,920
Less: Distributions to preferred unitholders	(9,684		)	(3,384		)
Less: Net loss (income) allocated to general partner (1)	40			(203		)
Less: Repurchase of warrants (2)	(349		)	—
Net (loss) income allocated to common unitholders (basic)	(73,355		)	173,333
Effect of dilutive securities	—			3,381
Net (loss) income allocated to common unitholders (diluted)	$	(73,355	)	$	176,714
Basic (loss) income per common unit	$	(0.61	)	$	1.66
Diluted (loss) income per common unit	$	(0.61	)	$	1.38
Basic weighted average common units outstanding	120,535,909			104,169,573
Diluted weighted average common units outstanding	120,535,909			128,453,733


(1)	Net loss (income) allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are discussed in Note 10.


(2)	This amount represents the excess of the repurchase price over the fair value of the warrants, as discussed further in Note 10.

Note 4—Acquisitions

The following summarizes our acquisitions during the three months ended June 30, 2017:

Acquisition of Remaining Interest in NGL Solids Solutions, LLC

On April 17, 2017, we entered into a purchase and sale agreement with the party owning the 50% noncontrolling interest in NGL Solids Solutions, LLC, a consolidated subsidiary, in our Water Solutions segment. Total consideration was $23.1 million, which consisted of cash of $20.0 million and the termination of a non-compete agreement that we valued at $3.1 million and in return we received the following:


•	The remaining 50% interest in NGL Solids Solutions, LLC; and


•	Two parcels of land to develop saltwater disposal wells.

We accounted for the transaction as an acquisition of assets. Acquiring assets in groups requires not only ascertaining the cost of the asset (or net asset) group but also allocating that cost to the individual assets (or individual assets and liabilities) that make up the group. The cost of a group of assets acquired in an asset acquisition is allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and does not give rise to goodwill or bargain purchase gains. We allocated $22.9 million to noncontrolling interest and $0.2 million to land. The acquisition of the remaining interest was accounted for as an equity transaction, no gain or loss was recorded and the carrying value of the noncontrolling interest was adjusted to reflect the change in ownership interest of the subsidiary. As of the date of the transaction, the 50% noncontrolling interest had a carrying value of $16.6 million. For the termination of the non-compete agreement, we recorded a gain of $1.3 million, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7). This gain was recorded within gain on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations during the three months ended June 30, 2017.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following summarizes the status of the preliminary purchase price allocation of acquisitions prior to April 1, 2017:

Water Solutions Facilities

During the three months ended June 30, 2017, we completed the acquisition accounting for one water solutions facility. There were no adjustments to the fair value of assets acquired and liabilities assumed during the three months ended June 30, 2017.

We are in the process of finalizing the fair value of the property, plant and equipment acquired and asset retirement obligations assumed for one water solutions facility acquired in September 2016, and as a result, the estimates of fair value at March 31, 2017 are subject to change.

Retail Propane Businesses

During the three months ended June 30, 2017, we completed the acquisition accounting for two retail propane businesses. There were no adjustments to the fair value of assets acquired and liabilities assumed during the three months ended June 30, 2017.

We are in the process of finalizing the fair value of the property, plant and equipment acquired for one retail propane business acquired in October 2016, and as a result, the estimates of fair value at March 31, 2017 are subject to change.

Natural Gas Liquids Facilities

During the three months ended June 30, 2017, we completed the acquisition accounting for certain natural gas liquids facilities acquired in January 2017. There were no material adjustments to the fair value of assets acquired and liabilities assumed during the three months ended June 30, 2017.

Note 5—Property, Plant and Equipment

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



Description	Estimated Useful Lives	June 30, 2017			March 31, 2017
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	236,363		$	207,825
Pipeline and related facilities	30–40 years	253,022			248,582
Refined products terminal assets and equipment	15–25 years	6,736			6,736
Retail propane equipment	2–30 years	240,861			239,417
Vehicles and railcars	3–25 years	196,576			198,480
Water treatment facilities and equipment	3–30 years	566,306			557,100
Crude oil tanks and related equipment	2–30 years	220,732			203,003
Barges and towboats	5–30 years	91,263			91,037
Information technology equipment	3–7 years	44,009			43,880
Buildings and leasehold improvements	3–40 years	170,651			161,957
Land		59,261			56,545
Tank bottoms and line fill (1)		24,462			24,462
Other	3–20 years	23,630			39,132
Construction in progress		36,603			87,711
		2,170,475			2,165,867
Accumulated depreciation		(400,857		)	(375,594		)
Net property, plant and equipment		$	1,769,618		$	1,790,273


(1)	Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. Line fill, which represents our portion of the product volume required for the operation of the proportionate share of a pipeline we own, is recorded at historical cost.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:



	Three Months Ended June 30,
	2017		2016
	(in thousands)
Depreciation expense	$	32,344	$	27,654
Capitalized interest expense	$	—	$	3,735

We record losses (gains) from the sales of property, plant and equipment and any write-downs in value due to impairment within gain on disposal or impairment of assets, net in our unaudited condensed consolidated statements of operations. During the three months ended June 30, 2017, we recorded a net gain of $2.5 million, of which $3.4 million related to a gain on the sale of excess pipe in our Crude Oil Logistics segment.

Note 6—Goodwill

There were no changes to goodwill during the three months ended June 30, 2017.

Note 7—Intangible Assets

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



		June 30, 2017						March 31, 2017
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	906,782	$	337,455	$	569,327	$	906,782	$	316,242	$	590,540
Customer commitments	10 years	310,000		20,667		289,333		310,000		12,917		297,083
Pipeline capacity rights	30 years	161,785		13,000		148,785		161,785		11,652		150,133
Rights-of-way and easements	1–40 years	63,766		2,931		60,835		63,402		2,154		61,248
Executory contracts and other agreements	3–30 years	29,036		21,468		7,568		29,036		20,457		8,579
Non-compete agreements	2–32 years	29,718		17,274		12,444		32,984		17,762		15,222
Trade names	1–10 years	15,439		13,486		1,953		15,439		13,396		2,043
Debt issuance costs (1)	5 years	40,789		21,111		19,678		38,983		20,025		18,958
Total amortizable		1,557,315		447,392		1,109,923		1,558,411		414,605		1,143,806
Non-amortizable:
Trade names		20,150		—		20,150		20,150		—		20,150
Total non-amortizable		20,150		—		20,150		20,150		—		20,150
Total		$	1,577,465	$	447,392	$	1,130,073	$	1,578,561	$	414,605	$	1,163,956


(1)	Includes debt issuance costs related to the Revolving Credit Facility (as defined herein). Debt issuance costs related to fixed-rate notes are reported as a reduction of the carrying amount of long-term debt. We incurred $1.8 million in debt issuance costs related to the June 2017 amendment and restatement of our Credit Agreement (as defined herein).

The weighted-average remaining amortization period for intangible assets is approximately 11.0 years.

Write off of Intangible Assets

During the three months ended June 30, 2017, we wrote off $1.8 million related to the non-compete agreement which was terminated as part of our acquisition of the remaining interest in NGL Solids Solutions, LLC (see Note 4).

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Amortization expense is as follows for the periods indicated:



	Three Months Ended June 30,
Recorded In	2017		2016
	(in thousands)
Depreciation and amortization	$	31,535	$	21,252
Cost of sales	1,585		1,596
Interest expense	1,086		1,725
Total	$	34,206	$	24,573

Expected amortization of our intangible assets is as follows (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	99,985
2019	128,423
2020	125,036
2021	111,928
2022	96,825
Thereafter	547,726
Total	$	1,109,923

Note 8—Long-Term Debt

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



	June 30, 2017							March 31, 2017
	Face Amount		Unamortized Debt Issuance Costs (1)			Book Value		Face Amount		Unamortized Debt Issuance Costs (1)			Book Value
	(in thousands)
Revolving credit facility:
Expansion capital borrowings	$	—	$	—		$	—	$	—	$	—		$	—
Working capital borrowings	769,500		—			769,500		814,500		—			814,500
Senior secured notes	195,000		(3,417		)	191,583		250,000		(4,559		)	245,441
Senior notes:
5.125% Notes due 2019	362,256		(2,697		)	359,559		379,458		(3,191		)	376,267
6.875% Notes due 2021	367,048		(5,472		)	361,576		367,048		(5,812		)	361,236
7.500% Notes due 2023	700,000		(11,043		)	688,957		700,000		(11,329		)	688,671
6.125% Notes due 2025	500,000		(8,378		)	491,622		500,000		(8,567		)	491,433
Other long-term debt	14,321		—			14,321		15,525		—			15,525
	2,908,125		(31,007		)	2,877,118		3,026,531		(33,458		)	2,993,073
Less: Current maturities	42,793		—			42,793		29,590		—			29,590
Long-term debt	$	2,865,332	$	(31,007	)	$	2,834,325	$	2,996,941	$	(33,458	)	$	2,963,483


(1)	Debt issuance costs related to the Revolving Credit Facility are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.

Amortization expense for debt issuance costs related to long-term debt in the table above was $1.7 million and $0.9 million during the three months ended June 30, 2017 and 2016, respectively.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Expected amortization of debt issuance costs is as follows (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	4,645
2019	6,099
2020	5,171
2021	4,788
2022	4,207
Thereafter	6,097
Total	$	31,007

Credit Agreement

We are party to a $1.765 billion credit agreement (the “Credit Agreement”) with a syndicate of banks. As of June 30, 2017, the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacity of $1.0 billion for cash borrowings and letters of credit, (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $765.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). We had letters of credit of $71.7 million on the Working Capital Facility at June 30, 2017.

At June 30, 2017 , the borrowings under the Credit Agreement had a weighted average interest rate of 3.99%, calculated as the weighted average LIBOR rate of 1.19% plus a margin of 2.75% for LIBOR borrowings and the prime rate of 4.25% plus a margin of 1.75% on alternate base rate borrowings. At June 30, 2017, the interest rate in effect on letters of credit was 2.75%. Commitment fees were charged at a rate ranging from 0.375% to 0.50% on any unused capacity.

On June 2, 2017, we amended our Credit Agreement. The amendment, among other things, restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1 and modifies our financial covenants. The following table summarizes the debt covenant levels specified in the Credit Agreement as of June 30, 2017:



		Senior Secured	Interest
Period Beginning	Leverage Ratio (1)	Leverage Ratio (1)	Coverage Ratio (2)
March 31, 2017	4.75	3.25	2.75
June 30, 2017	5.50	2.50	2.25
March 31, 2018	4.75	3.25	2.75
March 31, 2019 and thereafter	4.50	3.25	2.75


(1)	Amount represents the maximum ratio for the period presented.


(2)	Amount represents the minimum ratio for the period presented.

At June 30, 2017 our leverage ratio was approximately 5.18 to 1, our senior secured leverage ratio was approximately 0.49 to 1 and our interest coverage ratio was approximately 2.53 to 1.

At June 30, 2017, we were in compliance with the covenants under the Credit Agreement.

Senior Secured Notes

During the three months ended June 30, 2017, we repurchased $55.0 million of our senior secured notes for an aggregate purchase price of $57.2 million (excluding payments of accrued interest), and recorded a loss on the early extinguishment of $3.2 million (net of $1.0 million of debt issuance costs.) Following the repurchase, semi-annual installment payments will be $19.5 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Agreement and provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels. In addition, the amendment also restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our interest coverage ratio is less than 3.00 to 1.

At June 30, 2017, we were in compliance with the covenants under the note purchase agreement for our senior secured notes.

Senior Notes

During the three months ended June 30, 2017, we repurchased $17.2 million of our 5.125% senior notes due 2019 for an aggregate purchase price of $17.2 million (excluding payments of accrued interest), and recorded a loss on the early extinguishment of $0.1 million (net of $0.1 million of debt issuance costs.)

At June 30, 2017, we were in compliance with the covenants under the indentures for all of the senior notes.

Other Long-Term Debt

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. These instruments have a principal balance of $7.8 million at June 30, 2017, and the implied interest rates on these instruments range from 1.91% to 7.00% per year. We also have certain notes payable related to equipment financing. These instruments have a principal balance of $6.5 million at June 30, 2017, and the interest rates on these instruments range from 4.13% to 7.10% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at June 30, 2017:



Fiscal Year Ending March 31,	Revolving Credit Facility		Senior Secured Notes		Senior Notes		Other Long-Term Debt		Total
	(in thousands)
2018 (nine months)	$	—	$	19,500	$	—	$	3,359	$	22,859
2019	—		39,000		—		3,027		42,027
2020	—		39,000		362,256		2,228		403,484
2021	—		39,000		—		5,407		44,407
2022	769,500		39,000		367,048		241		1,175,789
Thereafter	—		19,500		1,200,000		59		1,219,559
Total	$	769,500	$	195,000	$	1,929,304	$	14,321	$	2,908,125

Note 9—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 unaudited condensed consolidated balance sheet at June 30, 2017 includes a liability, measured on an undiscounted basis, of $2.3 million related to environmental matters, which is recorded within accrued expenses and other payables in our unaudited condensed consolidated balance sheet. 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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (“Gavilon Energy”), of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by us in December 2013). On October 4, 2016, the U.S. Department of Justice, acting at the request of the EPA, filed a civil complaint in the Northern District of Iowa against Gavilon Energy and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint related to transactions between Gavilon Energy and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon Energy in 2011. On December 19, 2016, we filed a motion to dismiss the complaint. On January 9, 2017, the EPA filed an amended complaint. The amended complaint seeks an order declaring Western Dubuque’s RINs invalid and requiring the defendants to retire an equivalent number of valid RINs and that the defendants pay statutory civil penalties. On January 23, 2017, we filed a motion to dismiss the amended complaint, which was denied on May 24, 2017. Consistent with our position against the previous EPA allegations, and the original complaint, we deny the allegations in this amended civil complaint and intend to continue vigorously defending ourselves in the civil action. However, at this time we are unable to determine the outcome of this action or its significance to us.

Asset Retirement Obligations

We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions about the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events. The following table summarizes changes in our asset retirement obligation, which is reported within other noncurrent liabilities in our unaudited condensed consolidated balance sheets (in thousands):



Balance at March 31, 2017	$	8,181
Liabilities incurred	94
Accretion expense	145
Balance at June 30, 2017	$	8,420

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminable. We will record an asset retirement obligation for these assets in the periods in which settlement dates are reasonably determinable.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at June 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	107,711
2019	117,029
2020	105,320
2021	91,837
2022	61,832
Thereafter	90,749
Total	$	574,478

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Rental expense relating to operating leases was $31.3 million and $29.9 million during the three months ended June 30, 2017 and 2016, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement. We currently have a receivable recorded in other noncurrent assets in our unaudited condensed consolidated balance sheet for minimum shipping fees paid in previous periods that are expected to be recovered in future periods by exceeding the minimum monthly volumes (see Note 2).

The following table summarizes future minimum throughput payments under these agreements at June 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	39,078
2019	52,170
2020	42,418
Total	$	133,666

Construction Commitments

At June 30, 2017, we had construction commitments of $23.4 million.

Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods.

At June 30, 2017, we had the following purchase commitments (in thousands):



	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Purchase Commitments:
2018 (nine months)	$	64,882	1,425	$	20,282	34,984
2019	—		—	1,341		2,268
Total	$	64,882	1,425	$	21,623	37,252

Index-Price Purchase Commitments:
2018 (nine months)	$	602,405	14,444	$	567,089	917,281
2019	309,448		7,547	22,702		37,674
2020	287,148		6,808	—		—
2021	247,219		5,722	—		—
2022	148,782		3,355	—		—
Total	$	1,595,002	37,876	$	589,791	954,955

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At June 30, 2017, we had the following sale commitments (in thousands):



	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Sale Commitments:
2018 (nine months)	$	114,945	2,425	$	89,357	119,500
2019	—		—	4,206		5,880
2020	—		—	163		215
Total	$	114,945	2,425	$	93,726	125,595

Index-Price Sale Commitments:
2018 (nine months)	$	565,811	12,540	$	489,789	577,141
2019	87,299		1,825	3,989		5,979
2020	52,426		1,070	—		—
Total	$	705,536	15,435	$	493,778	583,120

We account for the contracts shown in the tables above using the normal purchase and normal sale election. 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 tables above may have offsetting derivative contracts (described in Note 11) or inventory positions (described in 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 unaudited condensed consolidated balance sheet and are not included in the tables above. These contracts are included in the derivative disclosures in Note 11, and represent $36.0 million of our prepaid expenses and other current assets and $23.3 million of our accrued expenses and other payables at June 30, 2017.

Note 10—Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner is not required to guarantee or pay any of our debts and obligations.

General Partner Contributions

In connection with the issuance of common units for the vesting of restricted units and the warrants that were converted to common units during the three months ended June 30, 2017, we issued 674 notional units to our general partner for less than $0.1 million in order to maintain its 0.1% interest in us.

Our Distributions

The following table summarizes distributions declared on our common units during the last two quarters:



Date Declared	Record Date	Date Paid/Payable	Amount Per Unit		Amount Paid/Payable to Limited Partners		Amount Paid/Payable to General Partner
					(in thousands)		(in thousands)
April 24, 2017	May 8, 2017	May 15, 2017	$	0.3900	$	46,870	$	80
July 20, 2017	August 4, 2017	August 14, 2017	$	0.3900	$	47,132	$	81

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Class A Convertible Preferred Units

During the three months ended June 30, 2016, we received net proceeds $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of 19,942,169 Class A Convertible Preferred Units (“Class A Preferred Units”) and 4,375,112 warrants.

We allocated the net proceeds on a relative fair value basis to the Class A Preferred Units, which includes the value of a beneficial conversion feature, and the warrants. Accretion for the beneficial conversion feature, recorded as a deemed distribution, was $3.2 million for the three months ended June 30, 2017.

The holders of the warrants may convert one-third of the warrants from and after the first anniversary of the original issue date, another one-third of the warrants from and after the second anniversary and the final one-third of the warrants from and after the third anniversary. The warrants have an exercise price of $0.01 and an eight year term. During the three months ended June 30, 2017, 607,653 warrants were converted to common units and we received proceeds of less than $0.1 million. In addition, we repurchased 850,716 unvested warrants for total proceeds of $10.5 million on June 23, 2017.

We pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Class A Preferred Units to the extent declared by the board of directors of our general partner.

The following table summarizes distributions declared on our Class A Preferred Units during the last two quarters:



		Amount Paid/Payable to Class A
Date Declared	Date Paid/Payable	Preferred Unitholders
		(in thousands)
April 24, 2017	May 15, 2017	$	6,449
July 20, 2017	August 14, 2017	$	6,449

Class B Preferred Units

During the three months ended June 30, 2017, we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $203.0 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.4 million).

Distributions on the Class B Preferred Units are payable on the 15th day of each January, April, July and October of each year (beginning on October 15, 2017) to holders of record on the first day of each payment month. The initial distribution rate for the Class B Preferred Units from and including the date of original issue to, but not including, July 1, 2022 is 9.00% per year of the $25.00 liquidation preference per unit (equal to $2.25 per unit per year). On and after July 1, 2022, distributions on the Class B Preferred Units will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR plus a spread of 7.213%.

At any time on or after July 1, 2022, we may redeem our Class B Preferred Units, in whole or in part, at a redemption price of $25.00 per Class B Preferred Unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Class B Preferred Units upon a change of control as defined in our partnership agreement. If we choose not to redeem the Class B Preferred Units, the Class B preferred unitholders may have the ability to convert the Class B Preferred Units to common units at the then applicable conversion rate. Class B preferred unitholders have no voting rights except with respect to certain matters set forth in our partnership agreement.

Amended and Restated Partnership Agreement

On June 13, 2017, NGL Energy Holdings LLC executed the Fourth Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Class B Preferred Units are defined in the amended and restated partnership agreement. The Class B Preferred Units rank senior to the common units, with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up and are on parity with the Class A Preferred Units. The Class B Preferred Units have no stated maturity but we may redeem the Class B Preferred Units at any time on or after July 1, 2022. Upon the occurrence of a change in control, we may redeem the Class B Preferred Units.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We did not issue any common units under the ATM Program during the three months ended June 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program at June 30, 2017.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based 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 upon a change of control, at the discretion of the board of directors of our general partner. No distributions accrue to or are paid on the restricted units during the vesting period.

The restricted units include both awards that: (i) vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”) and (ii) vest 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”).

On April 1, 2017, we made an accounting policy election to account for actual forfeitures, rather than estimate forfeitures each period (as previously required). As a result, the cumulative effect adjustment, which represents the differential between the amount of compensation expense previously recorded and the amount that would have been recorded without assuming forfeitures, had no impact on our consolidated financial statements.

The following table summarizes the Service Award activity during the three months ended June 30, 2017:



Unvested Service Award units at March 31, 2017	2,708,500
Units granted	80,421
Units vested and issued	(66,421	)
Units forfeited	(25,300	)
Unvested Service Award units at June 30, 2017	2,697,200

The following table summarizes the scheduled vesting of our unvested Service Award units at June 30, 2017:



Fiscal Year Ending March 31,
2018 (nine months)		875,400
2019		911,850
2020		907,450
2021		2,500
Total		2,697,200

Service Awards are valued at the closing price as of the grant date less the present value of the expected distribution stream over the vesting period using a risk-free interest rate. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, over the requisite service period of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion of the grant-date value of the award that is vested at that date. During the three months ended June 30, 2017 and 2016, we recorded compensation expense related to Service Award units of $5.3 million and $20.9 million, respectively.

Of the restricted units granted and vested during the three months ended June 30, 2017, 66,421 units were granted as a bonus for performance during the fiscal year ended March 31, 2017. We accrued expense of $0.9 million during the fiscal year ended March 31, 2017 as an estimate of the value of such bonus units that would be granted.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at June 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	9,038
2019	10,631
2020	2,804
2021	10
Total	$	22,483

During April 2015, our general partner granted Performance Award units to certain employees. 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. As of June 30, 2017, performance will be measured over the following periods:



Vesting Date of Tranche		Performance Period for Tranche
July 1, 2017		July 1, 2014 through June 30, 2017
July 1, 2018		July 1, 2015 through June 30, 2018
July 1, 2019		July 1, 2016 through June 30, 2019

During the three months ended June 30, 2017, there was no activity related to our Performance Award units.

During the July 1, 2014 through June 30, 2017 performance period, the return on our common units was below the return of the 50th percentile of our peer companies in the Index. As a result, no Performance Award units vested on July 1, 2017 and performance units with the July 1, 2017 vesting date are considered to be forfeited.

The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. 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. Any Performance Awards that do not become earned Performance Awards will terminate, expire and otherwise be forfeited by the participants. During the three months ended June 30, 2017 and 2016, we recorded compensation expense related to Performance Award units of $2.1 million and $1.5 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at June 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (nine months)	$	4,127
2019	3,232
2020	655
Total	$	8,014

At June 30, 2017, approximately 2.4 million common units remain available for issuance under the LTIP.

Note 11—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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Commodity Derivatives

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



	June 30, 2017						March 31, 2017
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	18,116		$	(1,800	)	$	2,590		$	(21,113	)
Level 2 measurements	36,686			(23,502		)	38,729			(27,799		)
	54,802			(25,302		)	41,319			(48,912		)

Netting of counterparty contracts (1)	(1,800		)	1,800			(1,508		)	1,508
Net cash collateral provided (held)	(5,301		)	(11		)	(1,035		)	19,604
Commodity derivatives	$	47,701		$	(23,513	)	$	38,776		$	(27,800	)


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

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



	June 30, 2017			March 31, 2017
	(in thousands)
Prepaid expenses and other current assets	$	47,123		$	38,711
Other noncurrent assets	578			65
Accrued expenses and other payables	(23,428		)	(27,622		)
Other noncurrent liabilities	(85		)	(178		)
Net commodity derivative asset	$	24,188		$	10,976

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



Contracts	Settlement Period	Net Long (Short) Notional Units (in barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
At June 30, 2017:
Crude oil fixed-price (1)	July 2017–September 2017	(775	)	$	604
Propane fixed-price (1)	July 2017–December 2018	560		583
Refined products fixed-price (1)	July 2017–January 2019	(4,037	)	25,419
Refined products index (1)	July 2017–December 2017	(12	)	(87		)
Other	July 2017–March 2022			2,981
				29,500
Net cash collateral held				(5,312		)
Net commodity derivative asset				$	24,188

At March 31, 2017:
Crude oil fixed-price (1)	April 2017–May 2017	(800	)	$	(55	)
Propane fixed-price (1)	April 2017–December 2018	220		1,082
Refined products fixed-price (1)	April 2017–January 2019	(4,682	)	(7,729		)
Refined products index (1)	April 2017–December 2017	(18	)	(103		)
Other	April 2017–March 2022			(788		)
				(7,593		)
Net cash collateral provided				18,569
Net commodity derivative asset				$	10,976


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

During the three months ended June 30, 2017, we recorded a net gain of $36.5 million and during the three months ended June 30, 2016, we recorded a net loss of $59.7 million from our commodity derivatives to cost of sales in our unaudited condensed consolidated statements of operations.

Credit Risk

We have credit policies that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At June 30, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our unaudited condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at June 30, 2017 (in thousands):



Senior secured notes	$	200,935
Senior notes
5.125% Notes due 2019	$	361,695
6.875% Notes due 2021	$	366,130
7.500% Notes due 2023	$	690,393
6.125% Notes due 2025	$	460,625

For the senior secured notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, 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. For the senior notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy.

Note 12—Segments

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

The “Corporate and Other” category in the table below includes certain corporate expenses that are not allocated to the reportable segments.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	480,285		$	414,619
Crude oil transportation and other	26,986			12,934
Elimination of intersegment sales	(2,356		)	(1,602		)
Total Crude Oil Logistics revenues	504,915			425,951
Water Solutions:
Service fees	33,321			25,697
Recovered hydrocarbons	9,960			7,196
Other revenues	3,686			2,860
Total Water Solutions revenues	46,967			35,753
Liquids:
Propane sales	136,860			96,471
Butane sales	68,232			54,575
Other product sales	84,303			59,160
Other revenues	6,012			7,147
Elimination of intersegment sales	(17,593		)	(12,304		)
Total Liquids revenues	277,814			205,049
Retail Propane:
Propane sales	48,632			41,641
Distillate sales	9,555			10,455
Other revenues	8,893			8,307
Elimination of intersegment sales	(8		)	(16		)
Total Retail Propane revenues	67,072			60,387
Refined Products and Renewables:
Refined products sales	2,773,607			1,876,857
Renewables sales	110,966			106,482
Service fees	118			11,266
Elimination of intersegment sales	(54		)	(42		)
Total Refined Products and Renewables revenues	2,884,637			1,994,563
Corporate and Other	161			267
Total revenues	$	3,781,566		$	2,721,970
Depreciation and Amortization:
Crude Oil Logistics	$	20,835		$	8,968
Water Solutions	24,008			24,434
Liquids	6,330			4,449
Retail Propane	11,462			9,687
Refined Products and Renewables	324			417
Corporate and Other	920			951
Total depreciation and amortization	$	63,879		$	48,906
Operating Income (Loss):
Crude Oil Logistics	$	4,357		$	(625	)
Water Solutions	(1,154		)	79,464
Liquids	(8,772		)	(57		)
Retail Propane	(5,868		)	(2,502		)
Refined Products and Renewables	14,496			149,769
Corporate and Other	(17,726		)	(32,149		)
Total operating (loss) income	$	(14,667	)	$	193,900

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



	Three Months Ended June 30,
	2017		2016
	(in thousands)
Crude Oil Logistics	$	7,058	$	72,305
Water Solutions	19,405		43,116
Liquids	542		6,468
Retail Propane	3,846		6,549
Refined Products and Renewables	—		24
Corporate and Other	269		1,118
Total	$	31,120	$	129,580

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



	June 30, 2017		March 31, 2017
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,694,378	$	1,724,805
Water Solutions	1,255,070		1,261,944
Liquids	613,361		619,204
Retail Propane	538,254		547,960
Refined Products and Renewables	213,883		215,637
Corporate and Other	36,461		36,395
Total	$	4,351,407	$	4,405,945

Total assets:
Crude Oil Logistics	$	2,405,538	$	2,538,768
Water Solutions	1,307,086		1,301,415
Liquids	817,997		767,597
Retail Propane	606,537		622,859
Refined Products and Renewables	911,361		988,073
Corporate and Other	70,196		101,667
Total	$	6,118,715	$	6,320,379

Note 13—Transactions with Affiliates

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

We purchase ethanol from E Energy Adams, LLC, an equity method investee (see Note 2). These transactions are reported within cost of sales in our unaudited condensed consolidated statements of operations.

Certain members of our management and members of their families as well as other associated parties own interests in entities from which we have purchased products and services and to which we have sold products and services. During the three months ended June 30, 2017, less than $0.1 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes these related party transactions for the periods indicated:



	Three Months Ended June 30,
	2017		2016
	(in thousands)
Sales to SemGroup	$	123	$	71
Purchases from SemGroup	$	1,017	$	2,025
Sales to equity method investees	$	98	$	405
Purchases from equity method investees	$	27,906	$	30,647
Sales to entities affiliated with management	$	83	$	77
Purchases from entities affiliated with management	$	197	$	8,243

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



	June 30, 2017		March 31, 2017
	(in thousands)
Receivables from SemGroup	$	1,482	$	6,668
Receivables from equity method investees	16		15
Receivables from entities affiliated with management	54		28
Total	$	1,552	$	6,711

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



	June 30, 2017		March 31, 2017
	(in thousands)
Payables to SemGroup	$	1,440	$	6,571
Payables to equity method investees	323		1,306
Payables to entities affiliated with management	14		41
Total	$	1,777	$	7,918

We have a loan receivable of $3.7 million at June 30, 2017 from Victory Propane, LLC, an equity method investee (see Note 2), with an initial maturity date of March 31, 2021, which can be extended for successive one-year periods unless one of the parties terminates the loan agreement.

On June 23, 2017, we repurchased outstanding warrants, as discussed further in Note 10, from funds managed by Oaktree Capital Management, L.P., who are represented on our board of directors.

Note 14—Unaudited Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the senior notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the unaudited condensed consolidating financial information for NGL Energy Partners LP (Parent), NGL Energy Finance Corp., the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below. NGL Energy Partners LP and NGL Energy Finance Corp. are co-issuers of the senior notes. Since NGL Energy Partners LP received the proceeds from the issuance of the senior notes, all activity has been reflected in the NGL Energy Partners LP (Parent) column in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the senior notes.

There are no significant restrictions that prevent the parent or any of the guarantor subsidiaries from obtaining funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries (other than the

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

For purposes of the tables below, (i) the unaudited 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 unaudited condensed consolidating statement of cash flow tables below.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Balance Sheet

(in Thousands)



	June 30, 2017
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,847	$	—	$	6,980		$	2,721		$	—		$	19,548
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		650,373			2,356			—			652,729
Accounts receivable-affiliates	—		—		1,552			—			—			1,552
Inventories	—		—		562,490			603			—			563,093
Prepaid expenses and other current assets	—		—		96,361			451			—			96,812
Total current assets	9,847		—		1,317,756			6,131			—			1,333,734
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,737,694			31,924			—			1,769,618
GOODWILL	—		—		1,438,959			12,757			—			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,116,073			14,000			—			1,130,073
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		190,948			—			—			190,948
NET INTERCOMPANY RECEIVABLES (PAYABLES)	2,515,786		—		(2,494,298		)	(21,488		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,882,025		—		25,044			—			(1,907,069		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		3,700			—			—			3,700
OTHER NONCURRENT ASSETS	—		—		238,926			—			—			238,926
Total assets	$	4,407,658	$	—	$	3,574,802		$	43,324		$	(1,907,069	)	$	6,118,715
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	521,538		$	617		$	—		$	522,155
Accounts payable-affiliates	1		—		1,776			—			—			1,777
Accrued expenses and other payables	33,719		—		158,387			743			—			192,849
Advance payments received from customers	—		—		56,529			542			—			57,071
Current maturities of long-term debt	39,000		—		3,409			384			—			42,793
Total current liabilities	72,720		—		741,639			2,286			—			816,645
LONG-TERM DEBT, net of debt issuance costs and current maturities	2,054,297		—		778,976			1,052			—			2,834,325
OTHER NONCURRENT LIABILITIES	—		—		172,162			4,406			—			176,568
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	67,048		—		—			—			—			67,048
REDEEMABLE NONCONTROLLING INTEREST	—		—		—			3,251			—			3,251
EQUITY:
Partners’ equity	2,213,593		—		1,884,016			32,541			(1,914,354		)	2,215,796
Accumulated other comprehensive loss	—		—		(1,991		)	(212		)	—			(2,203		)
Noncontrolling interests	—		—		—			—			7,285			7,285
Total equity	2,213,593		—		1,882,025			32,329			(1,907,069		)	2,220,878
Total liabilities and equity	$	4,407,658	$	—	$	3,574,802		$	43,324		$	(1,907,069	)	$	6,118,715

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Balance Sheet

(in Thousands)



	March 31, 2017
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,257	$	—	$	2,903		$	3,104		$	—		$	12,264
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		795,479			5,128			—			800,607
Accounts receivable-affiliates	—		—		6,711			—			—			6,711
Inventories	—		—		560,769			663			—			561,432
Prepaid expenses and other current assets	—		—		102,703			490			—			103,193
Total current assets	6,257		—		1,468,565			9,385			—			1,484,207
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,725,383			64,890			—			1,790,273
GOODWILL	—		—		1,437,759			13,957			—			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,149,524			14,432			—			1,163,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		187,423			—			—			187,423
NET INTERCOMPANY RECEIVABLES (PAYABLES)	2,424,730		—		(2,408,189		)	(16,541		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,978,158		—		47,598			—			(2,025,756		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		3,200			—			—			3,200
OTHER NONCURRENT ASSETS	—		—		239,436			168			—			239,604
Total assets	$	4,409,145	$	—	$	3,850,699		$	86,291		$	(2,025,756	)	$	6,320,379
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	657,077		$	944		$	—		$	658,021
Accounts payable-affiliates	1		—		7,907			10			—			7,918
Accrued expenses and other payables	42,150		—		164,012			963			—			207,125
Advance payments received from customers	—		—		35,107			837			—			35,944
Current maturities of long-term debt	25,000		—		4,211			379			—			29,590
Total current liabilities	67,151		—		868,314			3,133			—			938,598
LONG-TERM DEBT, net of debt issuance costs and current maturities	2,138,048		—		824,370			1,065			—			2,963,483
OTHER NONCURRENT LIABILITIES	—		—		179,857			4,677			—			184,534
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	63,890		—		—			—			—			63,890
REDEEMABLE NONCONTROLLING INTEREST	—		—		—			3,072			—			3,072
EQUITY:
Partners’ equity	2,140,056		—		1,979,785			74,545			(2,052,502		)	2,141,884
Accumulated other comprehensive loss	—		—		(1,627		)	(201		)	—			(1,828		)
Noncontrolling interests	—		—		—			—			26,746			26,746
Total equity	2,140,056		—		1,978,158			74,344			(2,025,756		)	2,166,802
Total liabilities and equity	$	4,409,145	$	—	$	3,850,699		$	86,291		$	(2,025,756	)	$	6,320,379

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Three Months Ended June 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	3,777,883		$	4,087		$	(404	)	$	3,781,566
COST OF SALES	—			—		3,641,494			1,018			(404		)	3,642,108
OPERATING COSTS AND EXPENSES:
Operating	—			—		74,504			1,965			—			76,469
General and administrative	—			—		24,804			187			—			24,991
Depreciation and amortization	—			—		62,433			1,446			—			63,879
(Gain) loss on disposal or impairment of assets, net	—			—		(11,879		)	665			—			(11,214		)
Operating Loss	—			—		(13,473		)	(1,194		)	—			(14,667		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		1,816			—			—			1,816
Interest expense	(38,371		)	—		(10,832		)	(226		)	203			(49,226		)
Loss on early extinguishment of liabilities, net	(3,281		)	—		—			—			—			(3,281		)
Other income, net	—			—		2,274			39			(203		)	2,110
Loss Before Income Taxes	(41,652		)	—		(20,215		)	(1,381		)	—			(63,248		)
INCOME TAX EXPENSE	—			—		(459		)	—			—			(459		)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(21,710		)	—		(1,036		)	—			22,746			—
Net Loss	(63,362		)	—		(21,710		)	(1,381		)	22,746			(63,707		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(52		)	(52		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS												397			397
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(9,684		)	(9,684		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												40			40
LESS: REPURCHASE OF WARRANTS												(349		)	(349		)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS	$	(63,362	)	$	—	$	(21,710	)	$	(1,381	)	$	13,098		$	(73,355	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Three Months Ended June 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	2,714,981		$	7,351		$	(362	)	$	2,721,970
COST OF SALES	—			—		2,565,828			974			(362		)	2,566,440
OPERATING COSTS AND EXPENSES:
Operating	—			—		70,881			4,291			—			75,172
General and administrative	—			—		41,626			245			—			41,871
Depreciation and amortization	—			—		46,309			2,597			—			48,906
(Gain) loss on disposal or impairment of assets, net	—			—		(204,339		)	20			—			(204,319		)
Operating Income (Loss)	—			—		194,676			(776		)	—			193,900
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		394			—			—			394
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(16,326		)	—		(14,028		)	(162		)	78			(30,438		)
Gain on early extinguishment of liabilities, net	8,614			—		21,338			—			—			29,952
Other income, net	—			—		3,836			14			(78		)	3,772
(Loss) Income Before Income Taxes	(7,712		)	—		191,851			(924		)	—			183,215
INCOME TAX EXPENSE	—			—		(462		)	—			—			(462		)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	184,632			—		(6,757		)	—			(177,875		)	—
Net Income (Loss)	176,920			—		184,632			(924		)	(177,875		)	182,753
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(5,833		)	(5,833		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(3,384		)	(3,384		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(203		)	(203		)
NET INCOME (LOSS) ALLOCATED TO COMMON UNITHOLDERS	$	176,920		$	—	$	184,632		$	(924	)	$	(187,295	)	$	173,333

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statements of Comprehensive Income (Loss)

(in Thousands)



	Three Months Ended June 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net loss	$	(63,362	)	$	—	$	(21,710	)	$	(1,381	)	$	22,746	$	(63,707	)
Other comprehensive loss	—			—		(364		)	(11		)	—		(375		)
Comprehensive loss	$	(63,362	)	$	—	$	(22,074	)	$	(1,392	)	$	22,746	$	(64,082	)



	Three Months Ended June 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income (loss)	$	176,920	$	—	$	184,632		$	(924	)	$	(177,875	)	$	182,753
Other comprehensive loss	—		—		(142		)	(10		)	—			(152		)
Comprehensive income (loss)	$	176,920	$	—	$	184,490		$	(934	)	$	(177,875	)	$	182,601

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Three Months Ended June 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	$	(60,756	)	$	—	$	26,788		$	34,959		$	991
INVESTING ACTIVITIES:
Capital expenditures	—			—		(31,164		)	(327		)	(31,491		)
Acquisitions, net of cash acquired	—			—		(19,897		)	—			(19,897		)
Cash flows from settlements of commodity derivatives	—			—		23,287			—			23,287
Proceeds from sales of assets	—			—		20,135			—			20,135
Investments in unconsolidated entities	—			—		(5,250		)	—			(5,250		)
Distributions of capital from unconsolidated entities	—			—		2,115			—			2,115
Payments on loan for natural gas liquids facility	—			—		2,401			—			2,401
Loan to affiliate	—			—		(500		)	—			(500		)
Net cash used in investing activities	—			—		(8,873		)	(327		)	(9,200		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		299,500			—			299,500
Payments on Revolving Credit Facility	—			—		(344,500		)	—			(344,500		)
Repurchase of senior secured and senior notes	(74,391		)	—		—			—			(74,391		)
Payments on other long-term debt	—			—		(1,297		)	(30		)	(1,327		)
Debt issuance costs	(294		)	—		(1,802		)	—			(2,096		)
Contributions from noncontrolling interest owners, net	—			—		—			23			23
Distributions to partners	(53,399		)	—		—			—			(53,399		)
Proceeds from sale of preferred units, net of offering costs	202,977			—		—			—			202,977
Repurchase of warrants	(10,549		)	—		—			—			(10,549		)
Payments for settlement and early extinguishment of liabilities	—			—		(745		)	—			(745		)
Net changes in advances with consolidated entities	2			—		35,006			(35,008		)	—
Net cash provided by (used in) financing activities	64,346			—		(13,838		)	(35,015		)	15,493
Net increase (decrease) in cash and cash equivalents	3,590			—		4,077			(383		)	7,284
Cash and cash equivalents, beginning of period	6,257			—		2,903			3,104			12,264
Cash and cash equivalents, end of period	$	9,847		$	—	$	6,980		$	2,721		$	19,548

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Three Months Ended June 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash used in operating activities	$	(18,411	)	$	—	$	(47,551	)	$	(4,578	)	$	(70,540	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(138,832		)	(1,347		)	(140,179		)
Acquisitions, net of cash acquired	—			—		(14,458		)	—			(14,458		)
Cash flows from settlements of commodity derivatives	—			—		(21,535		)	—			(21,535		)
Proceeds from sales of assets	—			—		421			17			438
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Distributions of capital from unconsolidated entities	—			—		2,941			—			2,941
Payments on loan for natural gas liquids facility	—			—		2,130			—			2,130
Loan to affiliate	—			—		(1,000		)	—			(1,000		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash used in investing activities	—			—		(74,183		)	(1,330		)	(75,513		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		433,500			—			433,500
Payments on Revolving Credit Facility	—			—		(454,500		)	—			(454,500		)
Repurchase of senior notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(1,777		)	(325		)	(2,102		)
Debt issuance costs	(11		)	—		(34		)	—			(45		)
Contributions from noncontrolling interest owners, net	(501		)	—		—			830			329
Distributions to partners	(40,696		)	—		—			—			(40,696		)
Distributions to noncontrolling interest owners	—			—		—			(1,355		)	(1,355		)
Proceeds from sale of preferred units, net of offering costs	235,180			—		—			—			235,180
Payments for settlement and early extinguishment of liabilities	—			—		(26,374		)	—			(26,374		)
Net changes in advances with consolidated entities	(177,872		)	—		171,715			6,157			—
Other	—			—		(53		)	—			(53		)
Net cash provided by financing activities	971			—		122,477			5,307			128,755
Net (decrease) increase in cash and cash equivalents	(17,440		)	—		743			(601		)	(17,298		)
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	8,309		$	—	$	1,527		$	1,042		$	10,878

Table of Contents

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months ended June 30, 2017. The discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as 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, 2017 (“Annual Report”) filed with the Securities and Exchange Commission on May 26, 2017.

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At June 30, 2017, our operations include:


•	Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.


•	Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.


•	Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.


•	Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.


•	Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.

Table of Contents

Consolidated Results of Operations

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



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Total revenues	$	3,781,566		$	2,721,970
Total cost of sales	3,642,108			2,566,440
Operating expenses	76,469			75,172
General and administrative expense	24,991			41,871
Depreciation and amortization	63,879			48,906
Gain on disposal or impairment of assets, net	(11,214		)	(204,319		)
Operating (loss) income	(14,667		)	193,900
Equity in earnings of unconsolidated entities	1,816			394
Revaluation of investments	—			(14,365		)
Interest expense	(49,226		)	(30,438		)
(Loss) gain on early extinguishment of liabilities, net	(3,281		)	29,952
Other income, net	2,110			3,772
(Loss) income before income taxes	(63,248		)	183,215
Income tax expense	(459		)	(462		)
Net (loss) income	(63,707		)	182,753
Less: Net income attributable to noncontrolling interests	(52		)	(5,833		)
Less: Net loss attributable to redeemable noncontrolling interests	397			—
Net (loss) income attributable to NGL Energy Partners LP	(63,362		)	176,920
Less: Distributions to preferred unitholders	(9,684		)	(3,384		)
Less: Net loss (income) allocated to general partner	40			(203		)
Less: Repurchase of warrants	(349		)	—
Net (loss) income allocated to common unitholders	$	(73,355	)	$	173,333

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, disposals and other transactions. Our results of operations for the three months ended June 30, 2017 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2018. See the detailed discussion of items affecting operating income (loss) by segment below.

Recent Developments

Class B Preferred Units

During the three months ended June 30, 2017, we issued 8,400,000 of our 9.00% Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) for net proceeds of $203.0 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.4 million). See Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of the Class B Preferred Units.

Credit Agreement

On June 2, 2017, we amended our Credit Agreement (as defined herein) to, among other things, modify our financial covenants and restrict increases to distributions. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description.

Table of Contents

Note Repurchases

During the three months ended June 30, 2017, we repurchased $55.0 million of our senior secured notes and $17.2 million of our 5.125% senior notes due 2019. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description.

Senior Secured Notes

On August 2, 2017, we amended the note purchase agreement for our senior secured notes with an effective date of June 2, 2017. The amendment, among other things, conforms the financial covenants to match the amended terms of Credit Agreement, provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels and restricts us from increasing our distribution rate. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description.

Acquisitions

As discussed below, we completed numerous acquisitions during the fiscal year ended March 31, 2017 and one during the three months ended June 30, 2017. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

During the three months ended June 30, 2017, in our Water Solutions segment, we acquired the remaining 50% ownership interest in NGL Solids Solutions, LLC. See Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

During the fiscal year ended March 31, 2017, we acquired:


•	three water solutions facilities;


•	the remaining 25% ownership interest in three water solutions facilities;


•	an additional 24.5% interest in an existing produced water pipeline company;


•	the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), in which we subsequently sold 100% of our interest;


•	four retail propane businesses; and


•	certain natural gas liquids facilities.

Table of Contents

Segment Operating Results for the Three Months Ended June 30, 2017 and 2016

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,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	480,285		$	414,619		$	65,666
Crude oil transportation and other	26,986			12,934			14,052
Total revenues (1)	507,271			427,553			79,718
Expenses:
Cost of sales	471,826			406,832			64,994
Operating expenses	12,169			9,114			3,055
General and administrative expenses	1,643			1,779			(136		)
Depreciation and amortization expense	20,835			8,968			11,867
(Gain) loss on disposal or impairment of assets, net	(3,559		)	1,485			(5,044		)
Total expenses	502,914			428,178			74,736
Segment operating income (loss)	$	4,357		$	(625	)	$	4,982

Crude oil sold (barrels)	10,020			9,541			479
Crude oil transported on owned pipelines (barrels)	6,766			—			6,766
Crude oil storage capacity - owned and leased (barrels) (2)	6,324			6,115			209
Crude oil storage capacity sub-leased to third parties (barrels) (2)	700			2,000			(1,300		)
Crude oil inventory (barrels) (2)	1,778			1,684			94
Crude oil sold ($/barrel)	$	47.933		$	43.457		$	4.476
Cost per crude oil sold ($/barrel)	$	47.088		$	42.640		$	4.448
Crude oil product margin ($/barrel)	$	0.845		$	0.817		$	0.028


(1)	Revenues include $2.4 million and $1.6 million of intersegment sales during the three months ended June 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of June 30, 2017 and June 30, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the three months ended June 30, 2017, compared to the three months ended June 30, 2016. This segment continued to be impacted by increased competition and lower margins in the majority of the basins across the United States and we continue to market crude volumes in this lower price environment to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 with revenues of $19.3 million, partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the three months ended June 30, 2017, compared to the three months ended June 30, 2016, and lower revenues in our barge operations during the three months ended June 30, 2017 due to a general slowdown in demand for transportation services, compared to the three months ended June 30, 2016.

Cost of Sales. The increase was due primarily to an increase in crude oil prices during the three months ended June 30, 2017, compared to the three months ended June 30, 2016. Our cost of sales during the three months ended June 30, 2017 was reduced by $4.4 million of net realized gains on derivatives and $0.7 million of net unrealized gains on derivatives. Our cost of sales during the three months ended June 30, 2016 was increased by $8.2 million of net realized losses on derivatives and reduced by $1.4 million of net unrealized gains on derivatives.

Table of Contents

Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the three months ended June 30, 2017, we incurred expenses of $3.2 million related to Grand Mesa.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the three months ended June 30, 2017, we incurred depreciation and amortization expense of $10.5 million related to Grand Mesa.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the three months ended June 30, 2017, we recorded a net gain of $3.6 million on the sales of excess pipe and certain other assets. During the three months ended June 30, 2016, we recorded a net loss of $1.5 million on the sales of certain assets.

Water Solutions

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



	Three Months Ended June 30,
	2017			2016			Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Service fees	$	33,321		$	25,697		$	7,624
Recovered hydrocarbons	9,960			7,196			2,764
Other revenues	3,686			2,860			826
Total revenues	46,967			35,753			11,214
Expenses:
Cost of sales-derivative (gain) loss	(192		)	5,041			(5,233		)
Cost of sales-other	345			160			185
Operating expenses	24,041			20,278			3,763
General and administrative expenses	649			646			3
Depreciation and amortization expense	24,008			24,434			(426		)
Gain on disposal or impairment of assets, net	(730		)	(94,270		)	93,540
Total expense (income), net	48,121			(43,711		)	91,832
Segment operating (loss) income	$	(1,154	)	$	79,464		$	(80,618	)

Wastewater processed (barrels per day)
Eagle Ford Basin	220,579			218,576			2,003
Permian Basin	232,105			136,351			95,754
DJ Basin	112,437			57,228			55,209
Other Basins	58,979			40,282			18,697
Total	624,100			452,437			171,663
Solids processed (barrels per day)	4,168			2,765			1,403
Skim oil sold (barrels per day)	2,525			2,000			525
Service fees for wastewater processed ($/barrel)	$	0.59		$	0.62		$	(0.03	)
Recovered hydrocarbons for wastewater processed ($/barrel)	$	0.18		$	0.17		$	0.01
Operating expenses for wastewater processed ($/barrel)	$	0.42		$	0.49		$	(0.07	)

Service Fee Revenues. The increase was due primarily to an increase in the volume of wastewater processed at existing facilities, partially offset by a lower price per barrel received in current market conditions. We continue to benefit from the increased rig counts in the basins in which we operate, particularly in the Permian and DJ Basins.

Recovered Hydrocarbon Revenues. The increase was due primarily to an increase in the volume of wastewater processed, partially offset by a decrease in the amount of hydrocarbons per barrel of wastewater processed.

Table of Contents

Other Revenues. Other revenues primarily include solids disposal revenues and water pipeline revenues. The increase was due primarily to an increase in volumes for solids disposal, water pipeline businesses as well as additional activity to truck wastewater to certain of our water solutions facilities. These increases were partially offset by a decrease in freshwater revenues due to the sale of Grassland in November 2016.

Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the three months ended June 30, 2017 included $0.2 million of net realized gains on derivatives. Our cost of sales during the three months ended June 30, 2016 included $3.7 million of net realized losses on derivatives and $1.3 million of net unrealized losses on derivatives.

Cost of Sales-Other. The increase was due to trucking expenses to bring wastewater to certain of our water solutions facilities.

Operating and General and Administrative Expenses. The increase was due primarily to higher operating costs of water disposal wells due to higher volumes processed, partially offset by cost reduction efforts.

Depreciation and Amortization Expense. The decrease was due primarily to acquisitions and developed facilities, partially offset by lower amortization expense from the write-off of an intangible asset during the three months ended June 30, 2016 as well as certain intangible assets being fully amortized during the fiscal year ended March 31, 2017.

Gain on Disposal or Impairment of Assets, Net. During the three months ended June 30, 2017, we recorded a gain of $1.3 million for the termination of a non-compete agreement, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report), partially offset by a net loss of $0.6 million on the sales of certain assets.

During the three months ended June 30, 2016, we recorded:


•	an adjustment of $124.7 million to the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016;


•	a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis in June 2016;


•	a loss of $22.7 million related to the termination of a development agreement in June 2016, which included the carrying value of the development agreement asset that was written off;


•	an impairment charge of $1.7 million to write down a loan receivable in June 2016; and


•	a loss of $0.8 million on the sales of certain assets.

Table of Contents

Liquids

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



	Three Months Ended June 30,
	2017			2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	136,860		$	96,471		$	40,389
Cost of sales	137,911			91,163			46,748
Product margin (loss)	(1,051		)	5,308			(6,359		)

Butane sales:
Revenues (1)	68,232			54,575			13,657
Cost of sales	66,262			53,938			12,324
Product margin	1,970			637			1,333

Other product sales:
Revenues (1)	84,303			59,160			25,143
Cost of sales	83,656			56,172			27,484
Product margin	647			2,988			(2,341		)

Other revenues:
Revenues (1)	6,012			7,147			(1,135		)
Cost of sales	838			2,023			(1,185		)
Product margin	5,174			5,124			50

Expenses:
Operating expenses	7,842			7,932			(90		)
General and administrative expenses	1,340			1,701			(361		)
Depreciation and amortization expense	6,330			4,449			1,881
Loss on disposal or impairment of assets, net	—			32			(32		)
Total expenses	15,512			14,114			1,398
Segment operating loss	$	(8,772	)	$	(57	)	$	(8,715	)

Liquids storage capacity - leased and owned (gallons) (2)	453,971			358,537			95,434

Propane sold (gallons)	224,733			204,284			20,449
Propane sold ($/gallon)	$	0.609		$	0.472		$	0.137
Cost per propane sold ($/gallon)	$	0.614		$	0.446		$	0.168
Propane product margin ($/gallon)	$	(0.005	)	$	0.026		$	(0.031	)
Propane inventory (gallons) (2)	94,488			112,756			(18,268		)
Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	33,495			33,264			231

Butane sold (gallons)	91,517			96,308			(4,791		)
Butane sold ($/gallon)	$	0.746		$	0.567		$	0.179
Cost per butane sold ($/gallon)	$	0.724		$	0.560		$	0.164
Butane product margin ($/gallon)	$	0.022		$	0.007		$	0.015
Butane inventory (gallons) (2)	76,047			48,509			27,538
Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	80,346			72,540			7,806

Other products sold (gallons)	90,611			79,660			10,951
Other products sold ($/gallon)	$	0.930		$	0.743		$	0.187
Cost per other products sold ($/gallon)	$	0.923		$	0.705		$	0.218
Other products product margin ($/gallon)	$	0.007		$	0.038		$	(0.031	)
Other products inventory (gallons) (2)	6,977			9,285			(2,308		)

Table of Contents


(1)	Revenues include $17.6 million and $12.3 million of intersegment sales during the three months ended June 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of June 30, 2017 and June 30, 2016, respectively.

Propane Sales. The increase in revenues was due to increased sales volumes and higher commodity prices.

Our cost of wholesale propane sales was increased by $0.3 million of net unrealized losses on derivatives and reduced by $0.1 million of net realized gains on derivatives during the three months ended June 30, 2017. During the three months ended June 30, 2016, our cost of wholesale propane sales was reduced by $0.9 million of net unrealized gains on derivatives and $0.5 million of net realized gains on derivatives.

Propane margins are lower primarily due to product storage costs and an increase in unrecovered railcar fleet costs.

Butane Sales. The increase in revenues and cost of sales was primarily due to higher commodity prices.

Our cost of butane sales during the three months ended June 30, 2017 was reduced by $1.7 million of net unrealized gains on derivatives, compared to an increase of $1.8 million of net unrealized losses on derivatives during the three months ended June 30, 2016. Additionally, our cost of butane sales was reduced by $0.2 million of net realized gains on derivatives and $0.4 million of net realized gains on derivatives during the three months ended June 30, 2017 and 2016, respectively.

Product margins per gallon of butane sold were higher during the three months ended June 30, 2017 than during the three months ended June 30, 2016 primarily due to the strategic use of our railcar fleet for storage during the blending off season.

Other Products Sales. The increase in the volume of other products sold was primarily due to a new long term marketing agreement.

Our cost of sales of other products was reduced by less than $0.1 million of net realized gains on derivatives during the three months ended June 30, 2017. Our cost of sales of other products during the three months ended June 30, 2016 was reduced by $0.1 million of net realized gains on derivatives.

Product margins during the three months ended June 30, 2017 were reduced due to an increase in unrecovered railcar fleet costs.

Other Revenues. This revenue includes storage, terminaling and transportation services income. The decrease was due to a decline in hauling activity and lower reduced storage service income.

Operating and General and Administrative Expenses. The decrease was due primarily to a decrease in incentive compensation and commission expense associated with lower product sales.

Depreciation and Amortization Expense. The increase was due primarily to additional assets being placed into service as well as the acquisition of two liquids facilities during the previous fiscal year.

Table of Contents

Retail Propane

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



	Three Months Ended June 30,
	2017			2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	48,632		$	41,641		$	6,991
Cost of sales	20,180			14,829			5,351
Product margin	28,452			26,812			1,640

Distillate sales:
Revenues (1)	9,555			10,455			(900		)
Cost of sales	7,015			7,538			(523		)
Product margin	2,540			2,917			(377		)

Other revenues:
Revenues (1)	8,893			8,307			586
Cost of sales	2,441			2,453			(12		)
Product margin	6,452			5,854			598

Expenses:
Operating expenses	28,641			25,217			3,424
General and administrative expenses	2,606			3,150			(544		)
Depreciation and amortization expense	11,462			9,687			1,775
Loss on disposal or impairment of assets, net	603			31			572
Total expenses	43,312			38,085			5,227
Segment operating loss	$	(5,868	)	$	(2,502	)	$	(3,366	)

Propane sold (gallons)	27,248			25,616			1,632
Propane sold ($/gallon)	$	1.785		$	1.626		$	0.159
Cost per propane sold ($/gallon)	$	0.741		$	0.579		$	0.162
Propane product margin ($/gallon)	$	1.044		$	1.047		$	(0.003	)
Propane inventory (gallons) (2)	9,868			8,539			1,329

Distillates sold (gallons)	4,504			5,417			(913		)
Distillates sold ($/gallon)	$	2.121		$	1.930		$	0.191
Cost per distillates sold ($/gallon)	$	1.558		$	1.392		$	0.166
Distillates product margin ($/gallon)	$	0.563		$	0.538		$	0.025
Distillates inventory (gallons) (2)	2,022			2,166			(144		)


(1)	Revenues include less than $0.1 million and less than $0.1 million of intersegment sales during the three months ended June 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of June 30, 2017 and June 30, 2016, respectively.

Revenues. Propane revenues and volumes increased due to four acquisitions in the prior year and the increase in commodity prices. Distillates revenues and volumes decreased due to a continuation of warmer than normal temperatures in April.

Cost of Sales. The increase in propane cost is due to the prior year acquisitions of four companies as well as an increase in commodity prices. The distillates cost decrease was due to a decrease in volumes offset by an increase in commodity prices.

Table of Contents

Operating and General and Administrative Expenses. The increase was due primarily to increased operating expenses and integration costs from acquisitions of four retail propane businesses during the previous fiscal year.

Depreciation and Amortization Expense. The increase was due primarily from the acquisition of four retail propane businesses during the previous fiscal year.

Loss on Disposal or Impairment of Assets, Net. The increase was due primarily to increased sale activity of non-core assets.

Table of Contents

Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:



	Three Months Ended June 30,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Refined products sales:
Revenues (1)	$	2,773,607		$	1,876,857		$	896,750
Cost of sales	2,761,072			1,834,327			926,745
Product margin	12,535			42,530			(29,995		)

Renewables sales:
Revenues	110,966			106,482			4,484
Cost of sales	110,684			105,802			4,882
Product margin	282			680			(398		)

Service fee revenues	118			11,266			(11,148		)

Expenses:
Operating expenses	3,551			12,322			(8,771		)
General and administrative expenses	2,092			3,565			(1,473		)
Depreciation and amortization expense	324			417			(93		)
Gain on disposal or impairment of assets, net	(7,528		)	(111,597		)	104,069
Total income, net	(1,561		)	(95,293		)	93,732
Segment operating income	$	14,496		$	149,769		$	(135,273	)

Gasoline sold (barrels)	28,516			19,944			8,572
Diesel sold (barrels)	13,798			10,859			2,939
Ethanol sold (barrels)	1,014			1,030			(16		)
Biodiesel sold (barrels)	627			751			(124		)
Refined products and renewables storage capacity - leased (barrels) (2)	9,225			7,140			2,085
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)	1,043			901			142
Gasoline inventory (barrels) (2)	2,748			2,532			216
Diesel inventory (barrels) (2)	1,973			2,391			(418		)
Ethanol inventory (barrels) (2)	586			426			160
Biodiesel inventory (barrels) (2)	255			240			15
Refined products sold ($/barrel)	$	65.548		$	60.931		$	4.617
Cost per refined products sold ($/barrel)	$	65.252		$	59.550		$	5.702
Refined products product margin ($/barrel)	$	0.296		$	1.381		$	(1.085	)
Renewable products sold ($/barrel)	$	67.621		$	59.788		$	7.833
Cost per renewable products sold ($/barrel)	$	67.449		$	59.406		$	8.043
Renewable products product margin ($/barrel)	$	0.172		$	0.382		$	(0.210	)


(1)	Revenues include $0.1 million and less than $0.1 million of intersegment sales during the three months ended June 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of June 30, 2017 and June 30, 2016, respectively.

Refined Products Sales and Cost of Sales. The increases in revenues and cost of sales were due to an increase in refined products prices and increased volumes. The increased volumes were due primarily to additional pipeline capacity rights

Table of Contents

purchased during the fiscal year ended March 31, 2017, an expansion of our refined products operations, and the continued demand for motor fuels in the current low gasoline price environment. The decrease in margin was due primarily to the negative impact of the continued decline in gasoline line space values on the Colonial Pipeline, discretionary terminal volume profitability and line space sales during the three months ended June 30, 2017 as well as Gulf Coast prices decreasing, on which our sales contracts are based, resulting in our average sale price decreasing more relative to our cost of sales. During the three months ended June 30, 2016, Gulf Coast prices increased, which resulted in our average sale price increasing more relative to our cost of sales and due to basis strengthening (i.e. Gulf Coast prices, on which our sales contracts are based, increased more than New York Harbor prices, which our futures contracts are based), which had a favorable impact on our cost of sales.

Renewables Sales and Cost of Sales. The increases in revenues and cost of sales were due primarily to an increase in renewables prices, partially offset by decreased volumes. The decreased volumes were due primarily to lower margins in current market conditions.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses. The decrease was due primarily to the expiration of a transition services agreement in October 2016 related to the sale of all of the TransMontaigne Partners L.P. (“TLP”) units we owned whereby we were reimbursed for certain expenses incurred on behalf of a third party.

Depreciation and Amortization Expense. The decrease was due primarily to certain assets being fully depreciated during the fiscal year ended March 31, 2017.

Gain on Disposal or Impairment of Assets, Net. During the three months ended June 30, 2017, we recorded $7.5 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

During the three months ended June 30, 2016, we recorded:


•	a $104.1 million gain from the sale of all of the TLP units we owned; and


•	$7.5 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:



	Three Months Ended June 30,
	2017			2016			Change
	(in thousands)
Other revenues	$	161		$	267		$	(106	)

Expenses:
Cost of sales	73			110			(37		)
Operating expenses	233			325			(92		)
General and administrative expenses	16,661			31,030			(14,369		)
Depreciation and amortization expense	920			951			(31		)
Total expenses	17,887			32,416			(14,529		)
Operating loss	$	(17,726	)	$	(32,149	)	$	14,423

General and Administrative Expenses. The decrease during the three months ended June 30, 2017 was due primarily to lower incentive compensation expense.

The decrease in incentive compensation was primarily related to our service awards units. During the three months ended June 30, 2017, expense related to the service award units was $5.3 million, compared to $20.9 million during the three months ended June 30, 2016. During the three months ended June 30, 2016, the expense for the service award units was

Table of Contents

accounted for under the liability method. The increase in the prior year was due to the increased unit price from the beginning of the quarter to the end of the quarter.

Equity in Earnings of Unconsolidated Entities

The increase of $1.4 million during the three months ended June 30, 2017 was due primarily to increased earnings related to our investment in Glass Mountain Pipeline, LLC (“Glass Mountain”).

Revaluation of Investments

As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland. Prior to the completion of this transaction, we accounted for our previously held 35% ownership interest in Grassland using the equity method of accounting. As we owned a controlling interest in Grassland, we revalued our previously held 35% ownership interest to fair value and recorded a loss of $14.9 million. As the amount paid (cash plus the fair value of our previously held ownership interest) was less than the fair value of the assets acquired and liabilities assumed, we recorded a bargain purchase gain of $0.6 million.

Interest Expense

Interest expense includes interest expense on our Revolving Credit Facility and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of $18.8 million during the three months ended June 30, 2017 was due primarily to the issuance of $700.0 million of fixed-rate notes during October 2016 and the issuance of $500.0 million of fixed-rate notes during February 2017.

(Loss) Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of (loss) gain on early extinguishment of liabilities, net for the periods indicated:



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Early extinguishment of long-term debt (1)	$	(3,281	)	$	8,614
Release of contingent consideration liabilities (2)	—			21,338
(Loss) gain on early extinguishment of liabilities, net	$	(3,281	)	$	29,952

(1)

During the three months ended June 30, 2017, this relates to losses on the early extinguishment of a portion of the senior secured notes and the 5.125% senior notes due 2019. During the three months ended June 30, 2016, this relates to gains on the early extinguishment of a portion of the 5.125% senior notes due 2019 and the 6.875% senior notes due 2021. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.


(2)	Relates to the release of certain contingent consideration liabilities in conjunction with the termination of a development agreement in June 2016.

Table of Contents

Other Income, Net

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



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Interest income (1)	$	2,078		$	2,423
Crude oil marketing arrangement (2)	(9		)	(1,521		)
Other (3)	41			2,870
Other income, net	$	2,110		$	3,772

(1)

Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13, respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion). As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on that receivable has been eliminated in consolidation subsequent to that date.


(2)	Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.


(3)	During the three months ended June 30, 2016, this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016.

Income Tax Expense

Income tax expense was $0.5 million during both the three months ended June 30, 2017 and 2016. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests - Redeemable and Non-redeemable

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The decrease of $6.2 million during the three months ended June 30, 2017 was due primarily to adjustments related to noncontrolling interests during the three months ended June 30, 2016.

Non-GAAP Financial Measures

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

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

Other than for our Refined Products and Renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract

Table of Contents

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 reconciliation table reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. We include this in Adjusted EBITDA because the unrealized gains and losses associated with derivative contracts associated with the inventory of this segment, which are intended primarily to hedge inventory holding risk and are included in net income, also affect Adjusted EBITDA.

The following table reconciles net (loss) income to EBITDA and Adjusted EBITDA:



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Net (loss) income	$	(63,707	)	$	182,753
Less: Net income attributable to noncontrolling interests	(52		)	(5,833		)
Less: Net loss attributable to redeemable noncontrolling interests	397			—
Net (loss) income attributable to NGL Energy Partners LP	(63,362		)	176,920
Interest expense	49,278			30,308
Income tax expense	459			462
Depreciation and amortization	68,063			52,580
EBITDA	54,438			260,270
Net unrealized (gains) losses on derivatives	(2,001		)	927
Inventory valuation adjustment (1)	(19,182		)	(6,837		)
Lower of cost or market adjustments	4,078			501
Gain on disposal or impairment of assets, net	(11,213		)	(204,355		)
Loss (gain) on early extinguishment of liabilities, net	3,281			(29,952		)
Revaluation of investments	—			14,365
Equity-based compensation expense (2)	8,821			22,334
Acquisition expense (3)	(318		)	437
Other (4)	880			6,119
Adjusted EBITDA	$	38,784		$	63,809


(1)	Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion.

(2)

Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 10 to our unaudited condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.


(3)	The amount for the three months ended June 30, 2017 represents reimbursement for certain legal costs incurred in prior periods, partially offset by expenses we incurred related to legal and advisory costs associated with acquisitions. The amount for the three months ended June 30, 2016 represents expenses we incurred related to legal and advisory costs associated with acquisitions.

(4)

The amount for the three months ended June 30, 2017 represents non-cash operating expenses related to our Grand Mesa Pipeline. The amount for the three months ended June 30, 2016 represents adjustments related to noncontrolling interests and the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.

Table of Contents

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



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	68,063		$	52,580
Intangible asset amortization recorded to cost of sales	(1,585		)	(1,596		)
Depreciation and amortization of unconsolidated entities	(2,999		)	(3,069		)
Depreciation and amortization attributable to noncontrolling interests	400			991
Depreciation and amortization per unaudited condensed consolidated statements of operations	$	63,879		$	48,906



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	68,063		$	52,580
Amortization of debt issuance costs recorded to interest expense	2,737			2,588
Depreciation and amortization of unconsolidated entities	(2,999		)	(3,069		)
Depreciation and amortization attributable to noncontrolling interests	400			991
Depreciation and amortization per unaudited condensed consolidated statements of cash flows	$	68,201		$	53,090

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



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Interest expense per EBITDA table	$	49,278		$	30,308
Interest expense attributable to noncontrolling interests	9			4
Other	(61		)	126
Interest expense per unaudited condensed consolidated statements of operations	$	49,226		$	30,438

Table of Contents

The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have reclassified certain prior period information to be consistent with the classification methods used in the current fiscal year.



	Three Months Ended June 30, 2017
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	4,357		$	(1,154	)	$	(8,772	)	$	(5,868	)	$	14,496		$	(17,726	)	$	(14,667	)
Depreciation and amortization	20,835			24,008			6,330			11,462			324			920			63,879
Amortization recorded to cost of sales	85			—			70			—			1,430			—			1,585
Net unrealized (gains) losses on derivatives	(659		)	—			(1,369		)	27			—			—			(2,001		)
Inventory valuation adjustment	—			—			—			—			(19,182		)	—			(19,182		)
Lower of cost or market adjustments	—			—			2,476			—			1,602			—			4,078
(Gain) loss on disposal or impairment of assets, net	(3,559		)	(730		)	—			603			(7,528		)	—			(11,214		)
Equity-based compensation expense	—			—			—			—			—			8,821			8,821
Acquisition expense	—			—			—			—			—			(318		)	(318		)
Other income, net	44			18			4			182			168			1,694			2,110
Adjusted EBITDA attributable to unconsolidated entities	3,822			154			—			8			891			—			4,875
Adjusted EBITDA attributable to noncontrolling interest	—			(244		)	—			182			—			—			(62		)
Other	880			—			—			—			—			—			880
Adjusted EBITDA	$	25,805		$	22,052		$	(1,261	)	$	6,596		$	(7,799	)	$	(6,609	)	$	38,784



	Three Months Ended June 30, 2016
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(625	)	$	79,464		$	(57	)	$	(2,502	)	$	149,769		$	(32,149	)	$	193,900
Depreciation and amortization	8,968			24,434			4,449			9,687			417			951			48,906
Amortization recorded to cost of sales	84			—			195			—			1,317			—			1,596
Net unrealized (gains) losses on derivatives	(1,394		)	1,359			892			70			—			—			927
Inventory valuation adjustment	—			—			—			—			(6,837		)	—			(6,837		)
Lower of cost or market adjustments	—			—			—			—			501			—			501
Loss (gain) on disposal or impairment of assets, net	1,485			(94,270		)	32			31			(111,597		)	—			(204,319		)
Equity-based compensation expense	—			—			—			—			—			22,334			22,334
Acquisition expense	—			—			—			2			—			435			437
Other (expense) income, net	(1,455		)	310			39			181			2,868			1,829			3,772
Adjusted EBITDA attributable to unconsolidated entities	2,688			(109		)	—			(166		)	894			—			3,307
Adjusted EBITDA attributable to noncontrolling interest	—			(837		)	—			122			—			—			(715		)
Adjusted EBITDA	$	9,751		$	10,351		$	5,550		$	7,425		$	37,332		$	(6,600	)	$	63,809

Table of Contents

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations, borrowings under our Revolving Credit Facility (as defined herein) and accessing capital markets. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a detailed description of our long-term debt. Our cash flows from operations are discussed below.

Our borrowing needs vary during the year due in part to the seasonal nature of our Liquids, Retail Propane and Refined Products & Renewables businesses. 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 as well as building our gasoline inventories in anticipation of the winter gasoline contango and blending 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 and gasoline inventories need to be minimized due to certain inventory requirements.

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.

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility (as defined herein) 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 or sell assets. 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.

Under current market conditions, we are much less likely to pursue acquisitions than we have been in the past. We continue to undertake certain capital expansion projects, including the Glass Mountain pipeline extension, among others. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility (as defined herein), asset sales or other forms of financing.

Other sources of liquidity during the three months ended June 30, 2017 are discussed below.

Class B Preferred Units

During the three months ended June 30, 2017, we issued 8,400,000 of our Class B Preferred Units representing limited partner interests at a price of $25.00 per unit for net proceeds of $203.0 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.4 million). See Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of the Class B Preferred Units.

Long-Term Debt

Credit Agreement

On June 2, 2017, we amended our Credit Agreement to, among other things, modify our financial covenants. In addition, the amendment also restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1.

At June 30, 2017, we were in compliance with the covenants under the Credit Agreement.

Table of Contents

Senior Secured Notes

On August 2, 2017, we amended the note purchase agreement for our senior secured notes with an effective date of June 2, 2017. The amendment, among other things, conforms the financial covenants to match the amended terms of Credit Agreement and provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels. In addition, the amendment also restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our interest coverage ratio is less than 3.00 to 1.

At June 30, 2017, we were in compliance with the covenants under the note purchase agreement for our senior secured notes.

Senior Notes

At June 30, 2017, we were in compliance with the covenants under the indentures for all of the senior notes.

For a further discussion of our Revolving Credit Facility, senior secured notes and senior notes, see Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Revolving Credit Balances

The following table summarizes our Revolving Credit Facility borrowings for the periods indicated:



	Average Balance Outstanding		Lowest Balance		Highest Balance
	(in thousands)
Three Months Ended June 30, 2017
Expansion capital borrowings	$	72,800	$	—	$	149,500
Working capital borrowings	$	791,590	$	764,500	$	839,500

Three Months Ended June 30, 2016
Expansion capital borrowings	$	1,263,500	$	1,153,500	$	1,338,000
Working capital borrowings	$	583,280	$	465,500	$	655,500

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We are under no obligation to issue equity under the ATM Program. We did not issue any common units under the ATM Program during the three months ended June 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program as of June 30, 2017.

Table of Contents

Capital Expenditures

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 and intangible assets acquired in acquisitions.



	Capital Expenditures
	Expansion		Maintenance		Total
	(in thousands)
Three Months Ended June 30,
2017	$	24,593	$	6,527	$	31,120
2016	$	95,103	$	6,295	$	101,398

Cash Flows

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



	Three Months Ended June 30,
Cash Flows Provided by (Used in)	2017			2016
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	(27,319	)	$	96,391
Changes in operating assets and liabilities	28,310			(166,931		)
Operating activities	$	991		$	(70,540	)
Investing activities	$	(9,200	)	$	(75,513	)
Financing activities	$	15,493		$	128,755

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories. In our Liquids and Retail Propane businesses, we typically experience operating losses or lower operating income during our first and second quarters, or the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. The heating season runs through the six months ending March 31. The seasonal motor fuel blending impacts the value of our gasoline inventory in our Refined Products and Renewables business and also represents a period when we build inventory into our system. We borrow under our Revolving Credit Facility to supplement our operating cash flows during the periods in which we are building inventory. Our operations, and as a result our cash flows, are also impacted by positive and negative movements in commodity prices, which cause fluctuations in the value of inventory, accounts receivable and payables, due to increases and decreases in revenues and cost of sales. The increase in net cash provided by operating activities during the three months ended June 30, 2017 was primarily a result of the decrease in inventory balances in our Refined Products and Renewables segment. During the three months ended June 30, 2016, inventory balances in our Refined Products and Renewables segment increased primarily due to the purchase of additional pipeline capacity rights.

Investing Activities. Net cash used in investing activities was $9.2 million during the three months ended June 30, 2017, compared to $75.5 million during the three months ended June 30, 2016. The decrease in net cash used in investing activities was due primarily to:


•	a decrease in capital expenditures from $140.2 million during the three months ended June 30, 2016, primarily related to the Grand Mesa Pipeline, to $31.5 million during the three months ended June 30, 2017;


•	a $44.8 million increase in cash flows from derivatives;


•	a $19.7 million increase in proceeds primarily from the sale of excess pipe in our Crude Oil Logistics segment during the three months ended June 30, 2017; and


•	a $16.9 million payment to terminate a development agreement during the three months ended June 30, 2016.

Table of Contents

These decreases in net cash used in investing activities were partially offset by $112.4 million in proceeds received from the sale of the TLP common units we owned during the three months ended June 30, 2016.

Financing Activities. Net cash provided by financing activities was $15.5 million during the three months ended June 30, 2017, compared to $128.8 million during the three months ended June 30, 2016. The decrease in net cash provided by financing activities was due primarily to:


•	an increase of $59.3 million in repurchases of a portion of our outstanding senior secured notes and senior notes during the three months ended June 30, 2017;


•	a decrease of $32.2 million in proceeds received from the sale of preferred units;


•	a decrease of $24.0 million in borrowings on our Revolving Credit Facility (net of repayments) during the three months ended June 30, 2017;


•	an increase of $11.3 million in distributions paid to our partners and noncontrolling interest owners during the three months ended June 30, 2017; and


•	$10.5 million for the repurchase of warrants related to our Class A Preferred Units during the three months ended June 30, 2017.

These decreases in net cash provided by financing activities were partially offset by a $25.6 million release of contingent consideration liabilities related to the termination of a development agreement during the three months ended June 30, 2016.

Distributions Declared

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. See further discussion of our cash distribution policy in Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities included in our Annual Report.

On July 20, 2017, the board of directors of our general partner declared a distribution of $0.39 per common unit to the unitholders of record on August 4, 2017. In addition, the board of directors declared a distribution to the holders of the Class A Preferred Units of $6.4 million in the aggregate. The distributions are to be paid to both the common unitholders and the holders of the Class A Preferred Units on August 14, 2017.

The initial distribution on the Class B Preferred Units will accumulate after the original issuance date until September 30, 2017 and will be payable on October 15, 2017, if declared.

Table of Contents

Contractual Obligations

The following table summarizes our contractual obligations at June 30, 2017 for our fiscal years ending thereafter:



			Nine Months Ending March 31,		Fiscal Year Ending March 31,
	Total		2018		2019		2020		2021		2022		Thereafter
	(in thousands)
Principal payments on long-term debt:
Expansion capital borrowings	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Working capital borrowings	769,500		—		—		—		—		769,500		—
Senior secured notes	195,000		19,500		39,000		39,000		39,000		39,000		19,500
Senior notes	1,929,304		—		—		362,256		—		367,048		1,200,000
Other long-term debt	14,321		3,359		3,027		2,228		5,407		241		59
Interest payments on long-term debt:
Revolving Credit Facility (1)	156,525		27,007		35,977		35,977		35,977		21,587		—
Senior secured notes	36,212		9,952		10,374		7,781		5,187		2,594		324
Senior notes	727,493		93,527		126,925		117,642		108,360		108,360		172,679
Other long-term debt	728		295		254		126		42		10		1
Letters of credit	71,682		—		—		—		—		71,682		—
Future minimum lease payments under noncancelable operating leases	574,478		107,711		117,029		105,320		91,837		61,832		90,749
Future minimum throughput payments under noncancelable agreements (2)	133,666		39,078		52,170		42,418		—		—		—
Construction commitments (3)	23,395		22,951		444		—		—		—		—
Fixed-price commodity purchase commitments:
Crude oil	64,882		64,882		—		—		—		—		—
Natural gas liquids	21,623		20,282		1,341		—		—		—		—
Index-price commodity purchase commitments (4):
Crude oil	1,595,002		602,405		309,448		287,148		247,219		148,782		—
Natural gas liquids	589,791		567,089		22,702		—		—		—		—
Total contractual obligations	$	6,903,602	$	1,578,038	$	718,691	$	999,896	$	533,029	$	1,590,636	$	1,483,312


(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at June 30, 2017. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

(2)

We have executed noncancelable agreements with crude oil operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information.


(3)	At June 30, 2017, construction commitments relate to the Glass Mountain pipeline extension and an expansion of a salt dome cavern.

(4)

Index prices are based on a forward price curve at June 30, 2017. A theoretical change of $0.10 per gallon in the underlying commodity price at June 30, 2017 would result in a change of $95.5 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, 2017 would result in a change of $37.9 million in the value of our index-price crude oil purchase commitments. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for further detail of the commitments.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases discussed in Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Table of Contents

Environmental Legislation

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.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

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 our operations and the use of estimates made by management. We have identified certain accounting policies that are most important to the portrayal of our consolidated financial position 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. There have been no material changes in the critical accounting policies previously disclosed in our Annual Report.

Table of Contents

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 our fixed-rate debt but do not impact its cash flows.

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, 2017, we had $769.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 3.99%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.0 million, based on borrowings outstanding at June 30, 2017.

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, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At June 30, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

The crude oil, natural gas liquids, and refined and renewables products industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined and renewables products.

We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, to protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

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 in our unaudited condensed consolidated statements of operations. The following table summarizes the hypothetical impact on the June 30, 2017 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)	$	(3,575	)
Propane (Liquids segment)	$	1,399
Other products (Liquids segment)	$	(3,744	)
Gasoline (Refined Products and Renewables segment)	$	(15,343	)
Diesel (Refined Products and Renewables segment)	$	(10,656	)
Ethanol (Refined Products and Renewables segment)	$	(3,444	)
Biodiesel (Refined Products and Renewables segment)	$	1,469
Canadian dollars (Liquids segment)	$	750

Table of Contents

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 the 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, 2017. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of June 30, 2017, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Table of Contents

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the captions “Legal Contingencies” and “Environmental Matters” in Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

Except for amending and restating the risk factor below, 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 fiscal year ended March 31, 2017.

The Preferred Units give the holders thereof liquidation and distribution preferences, certain rights relating to our business and management, and the ability to convert such units into our common units, potentially causing dilution to our common unitholders.

In June 2016, we issued 19,942,169 10.75% Class A Convertible Preferred Units and in June 2017, we issued 8,400,000 Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the “Preferred Units”), which rank senior to the common units with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, as long as any Preferred Units remain outstanding, we may not declare any distribution on our common units unless all accumulated and unpaid distributions have been declared and paid on the Preferred Units. In the event of our liquidation, winding-up or dissolution, the holders of the Preferred Units would have the right to receive proceeds from any such transaction before the holders of the common units. The payment of the liquidation preference could result in common unitholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common units, make it harder for us to sell common units in offerings in the future, or prevent or delay a change of control.

In connection with the issuance of the 10.75% Class A Convertible Preferred Units, we entered into an agreement with Oaktree Capital Management L.P. (“Oaktree”) pursuant to which we granted them the right to appoint one member to the board of directors of our general partner. In addition, the holders of the 10.75% Class A Convertible Preferred Units have the right to vote, under certain conditions, on an as-converted basis with our common unitholders on matters submitted to a unitholder vote. Also, as long as any 10.75% Class A Convertible Preferred Units are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding 10.75% Class A Convertible Preferred Units, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any action to be taken that adversely affects any of the rights, preferences or privileges of the 10.75% Class A Convertible Preferred Units, (ii) amending the terms of the 10.75% Class A Convertible Preferred Units, (iii) the issuance of any additional Preferred Units or equity security senior in right of distribution or in liquidation to the Preferred Units, (iv) any issuance of preferred equity securities by any of our consolidated controlled subsidiaries of any issued or authorized amount of, any specific class or series of securities, (v) any issuance by us of parity units, subject to certain exceptions and (vi) the ability to incur funded indebtedness for borrowed money if pro forma for such incurrence, the adjusted leverage ratio (as defined in the Credit Agreement) would exceed 5.50. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Furthermore, the conversion of the 10.75% Class A Convertible Preferred Units into common units, as early as three years from the issuance date of the Preferred Units, may cause substantial dilution to holders of the common units. Because the board of directors of our general partner is entitled to designate the powers and preferences of Preferred Units without a vote of our unitholders, subject to New York Stock Exchange rules and regulations, our unitholders will have no control over what designations and preferences our future preferred units, if any, will have.

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

On June 23, 2017, we repurchased 850,716 warrants, issued in connection with our Class A convertible preferred unit offering, from funds managed by Oaktree Capital Management L.P. for $10.5 million.

Table of Contents

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Table of Contents

Item 6. Exhibits



Exhibit Number		Exhibit
3.1		Fourth Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP, dated as of June 13, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 13, 2017)
4.1*		Amended and Restated Guaranty Agreement, dated as of March 31, 2017 and effective as of December 31, 2016, among NGL Energy Partners LP and the purchasers named therein
4.2*		Amendment No. 2 to Amended and Restated Note Purchase Agreement, dated August 2, 2017 and effective as of June 2, 2017, among NGL Energy Partners LP and the purchasers named therein
10.1		Amendment No. 2 to Amended and Restated Credit Agreement, dated as of June 2, 2017, among the NGL Energy Partners LP, NGL Energy Operating LLC, the other subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 5, 2017)
10.2		Waiver of Class A Preemptive Rights Holders and Option to Purchase Class C Preferred Units, dated June 6, 2017, by and among NGL Energy Partners and Highstar NGL Prism/IV-A Interco LLC, Highstar NGL Main Interco LLC, NGL CIV A, LLC and NGL Prism/IV-A Blocker, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 9, 2017)
12.1*		Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions
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) Unaudited Condensed Consolidated Balance Sheets at June 30, 2017 and March 31, 2017, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30, 2017 and 2016, (iii) Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three months ended June 30, 2017 and 2016, (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the three months ended June 30, 2017, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended June 30, 2017 and 2016, and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

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 4, 2017		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: August 4, 2017		By:	/s/ Robert W. Karlovich III
			Robert W. Karlovich III
			Chief Financial Officer

Table of Contents

INDEX TO EXHIBITS



Exhibit Number		Exhibit
3.1		Fourth Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP, dated as of June 13, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 13, 2017)
4.1*		Amended and Restated Guaranty Agreement, dated as of March 31, 2017 and effective as of December 31, 2016, among NGL Energy Partners LP and the purchasers named therein
4.2*		Amendment No. 2 to Amended and Restated Note Purchase Agreement, dated August 2, 2017 and effective as of June 2, 2017, among NGL Energy Partners LP and the purchasers named therein
10.1		Amendment No. 2 to Amended and Restated Credit Agreement, dated as of June 2, 2017, among the NGL Energy Partners LP, NGL Energy Operating LLC, the other subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 5, 2017)
10.2		Waiver of Class A Preemptive Rights Holders and Option to Purchase Class C Preferred Units, dated June 6, 2017, by and among NGL Energy Partners and Highstar NGL Prism/IV-A Interco LLC, Highstar NGL Main Interco LLC, NGL CIV A, LLC and NGL Prism/IV-A Blocker, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 9, 2017)
12.1*		Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions
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.