10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from __________ to __________

Commission File Number: 001-35172

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

At October 31, 2016, there were 107,444,272 common units issued and outstanding.

TABLE OF CONTENTS

PART I
Item 1.	Financial Statements (Unaudited)	3
	Condensed Consolidated Balance Sheets at September 30, 2016 and March 31, 2016	3
	Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2016 and 2015	4
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2016 and 2015	5
	Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2016	6
	Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2016 and 2015	7
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	81
Item 4.	Controls and Procedures	82
PART II
Item 1.	Legal Proceedings	83
Item 1A.	Risk Factors	83
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	83
Item 3.	Defaults Upon Senior Securities	83
Item 4.	Mine Safety Disclosures	83
Item 5.	Other Information	83
Item 6.	Exhibits	84
SIGNATURES		85
INDEX TO EXHIBITS		86

i

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, refined products, ethanol, and biodiesel;

• energy prices generally;

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

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

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

• the level of crude oil and natural gas drilling and production in producing areas 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, refined products, ethanol, and biodiesel;

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

• the availability of local, intrastate, and interstate transportation infrastructure 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, water disposal, recycling, and discharge services;

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

1

• the nonpayment or nonperformance by our counterparties;

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

• a deterioration of the credit and capital markets;

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

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

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

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

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

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Quarterly Report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks discussed under Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016 and under Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

2

PART I

Item 1.    Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

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

	September 30, 2016			March 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23,427		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts of $5,850 and $6,928, respectively	592,074			521,014
Accounts receivable-affiliates	3,540			15,625
Inventories	520,340			367,806
Prepaid expenses and other current assets	110,918			95,859
Total current assets	1,250,299			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $324,364 and $266,491, respectively	1,755,416			1,649,572
GOODWILL	1,467,955			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization of $356,314 and $316,878, respectively	1,190,147			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	190,662			219,550
LOAN RECEIVABLE-AFFILIATE	1,700			22,262
OTHER NONCURRENT ASSETS	217,739			176,039
Total assets	$	6,073,918		$	5,560,155
LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	512,104		$	420,306
Accounts payable-affiliates	6,244			7,193
Accrued expenses and other payables	184,634			214,426
Advance payments received from customers	87,825			56,185
Current maturities of long-term debt	8,046			7,907
Total current liabilities	798,853			706,017
LONG-TERM DEBT, net of debt issuance costs of $13,482 and $15,500, respectively, and current maturities	3,063,008			2,912,837
OTHER NONCURRENT LIABILITIES	198,001			247,236
COMMITMENTS AND CONTINGENCIES (NOTE 10)
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 0 preferred units issued and outstanding, respectively	58,742			—
EQUITY:
General partner, representing a 0.1% interest, 107,360 and 104,274 notional units, respectively	(50,735		)	(50,811		)
Limited partners, representing a 99.9% interest, 107,252,272 and 104,169,573 common units issued and outstanding, respectively	1,977,596			1,707,326
Accumulated other comprehensive loss	(642		)	(157		)
Noncontrolling interests	29,095			37,707
Total equity	1,955,314			1,694,065
Total liabilities, convertible preferred units and equity	$	6,073,918		$	5,560,155

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

3

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

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

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
REVENUES:
Crude Oil Logistics	$	349,885		$	1,007,578		$	775,836		$	2,335,362
Water Solutions	39,733			47,494			75,486			101,787
Liquids	234,260			258,992			439,309			507,977
Retail Propane	51,090			53,206			111,477			117,653
Refined Products and Renewables	2,370,322			1,825,925			4,364,885			3,668,885
Other	248			—			515			—
Total Revenues	3,045,538			3,193,195			5,767,508			6,731,664
COST OF SALES:
Crude Oil Logistics	340,518			982,719			745,748			2,274,711
Water Solutions	(1,807		)	(8,567		)	3,394			(4,960		)
Liquids	209,283			221,115			400,275			453,391
Retail Propane	20,691			20,879			45,511			50,443
Refined Products and Renewables	2,359,932			1,789,680			4,300,019			3,554,792
Other	113			—			223			—
Total Cost of Sales	2,928,730			3,005,826			5,495,170			6,328,377
OPERATING COSTS AND EXPENSES:
Operating	73,255			97,630			148,427			203,220
General and administrative	27,926			29,298			69,797			91,779
Depreciation and amortization	50,603			56,761			99,509			116,592
Loss (gain) on disposal or impairment of assets, net	852			1,291			(203,467		)	1,712
Revaluation of liabilities	—			(15,909		)	—			(27,104		)
Operating (Loss) Income	(35,828		)	18,298			158,072			17,088
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	53			2,432			447			11,150
Revaluation of investments	—			—			(14,365		)	—
Interest expense	(33,442		)	(31,571		)	(63,880		)	(62,373		)
Gain on early extinguishment of liabilities	938			—			30,890			—
Other income, net	2,081			1,955			5,853			780
(Loss) Income Before Income Taxes	(66,198		)	(8,886		)	117,017			(33,355		)
INCOME TAX (EXPENSE) BENEFIT	(460		)	2,786			(922		)	2,248
Net (Loss) Income	(66,658		)	(6,100		)	116,095			(31,107		)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	59			(3,497		)	(5,774		)	(7,847		)
NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	(66,599		)	(9,597		)	110,321			(38,954		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(8,668		)	—			(12,052		)	—
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	45			(16,185		)	(158		)	(31,559		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(75,222	)	$	(25,782	)	$	98,111		$	(70,513	)
BASIC (LOSS) INCOME PER COMMON UNIT	$	(0.71	)	$	(0.25	)	$	0.93		$	(0.67	)
DILUTED (LOSS) INCOME PER COMMON UNIT	$	(0.71	)	$	(0.25	)	$	0.91		$	(0.67	)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	106,186,389			105,189,463			105,183,556			104,542,427
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	106,186,389			105,189,463			107,997,549			104,542,427

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

4

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
Net (loss) income	$	(66,658	)	$	(6,100	)	$	116,095		$	(31,107	)
Other comprehensive loss	(333		)	(19		)	(485		)	(27		)
Comprehensive (loss) income	$	(66,991	)	$	(6,119	)	$	115,610		$	(31,134	)

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

5

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Six Months Ended September 30, 2016

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

				Limited Partners				Accumulated Other
	General Partner			Common Units	Amount			Comprehensive Loss			Noncontrolling Interests			Total Equity
BALANCES AT MARCH 31, 2016	$	(50,811	)	104,169,573	$	1,707,326		$	(157	)	$	37,707		$	1,694,065
Distributions	(141		)	—	(83,566		)	—			(2,750		)	(86,457		)
Contributions	59			—	(501		)	—			966			524
Business combinations	—			218,617	3,969			—			—			3,969
Purchase of noncontrolling interest (Notes 4 and 15)	—			—	(215		)	—			(12,602		)	(12,817		)
Equity issued pursuant to incentive compensation plan	—			2,340,082	54,781			—			—			54,781
Common units issued, net of offering costs	—			524,000	9,383			—			—			9,383
Allocation of value to beneficial conversion feature of Class A convertible preferred units	—			—	131,534			—			—			131,534
Issuance of warrants	—			—	48,550			—			—			48,550
Accretion of beneficial conversion feature of Class A convertible preferred units	—			—	(3,808		)	—			—			(3,808		)
Net income	158			—	110,163			—			5,774			116,095
Other comprehensive loss	—			—	—			(485		)	—			(485		)
Other	—			—	(20		)	—			—			(20		)
BALANCES AT SEPTEMBER 30, 2016	$	(50,735	)	107,252,272	$	1,977,596		$	(642	)	$	29,095		$	1,955,314

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

6

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

				As Restated
	Six Months Ended September 30,
	2016			2015
OPERATING ACTIVITIES:
Net income (loss)	$	116,095		$	(31,107	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation and amortization, including amortization of debt issuance costs	108,133			124,551
Gain on early extinguishment or revaluation of liabilities	(30,890		)	(27,104		)
Non-cash equity-based compensation expense	32,994			51,482
(Gain) loss on disposal or impairment of assets, net	(203,467		)	1,712
Provision for doubtful accounts	(122		)	3,046
Net commodity derivative loss (gain)	44,966			(44,534		)
Equity in earnings of unconsolidated entities	(447		)	(11,150		)
Distributions of earnings from unconsolidated entities	42			11,593
Revaluation of investments	14,365			—
Other	(485		)	(8		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(54,069		)	322,230
Inventories	(151,507		)	34,333
Other current and noncurrent assets	(44,798		)	(7,322		)
Accounts payable-trade and affiliates	90,496			(272,322		)
Other current and noncurrent liabilities	22,295			18,695
Net cash (used in) provided by operating activities	(56,399		)	174,095
INVESTING ACTIVITIES:
Capital expenditures	(159,680		)	(222,276		)
Purchases of pipeline capacity allocations	(41,953		)	—
Acquisitions of businesses, including acquired working capital, net of cash acquired	(113,297		)	(150,546		)
Cash flows from commodity derivatives	(25,015		)	43,032
Proceeds from sales of assets	396			3,567
Proceeds from sale of TLP common units	112,370			—
Investments in unconsolidated entities	—			(6,926		)
Distributions of capital from unconsolidated entities	5,233			8,207
Loan for natural gas liquids facility	—			(3,913		)
Payments on loan for natural gas liquids facility	4,324			3,546
Loan to affiliate	(1,700		)	(15,621		)
Payments on loan to affiliate	655			—
Payment to terminate development agreement	(16,875		)	—
Net cash used in investing activities	(235,542		)	(340,930		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	770,000			1,354,700
Payments on revolving credit facilities	(595,500		)	(1,006,600		)
Repurchases of senior notes	(15,129		)	—
Payments on other long-term debt	(4,423		)	(2,344		)
Debt issuance costs	(320		)	(1,380		)
Contributions from partners	(442		)	45
Contributions from noncontrolling interest owners	966			6,613
Distributions to partners	(83,707		)	(154,824		)
Distributions to noncontrolling interest owners	(2,750		)	(17,780		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018			—
Proceeds from sale of common units, net of offering costs	9,383			—
Payments for the early extinguishment of liabilities	(25,884		)	—
Taxes paid on behalf of equity incentive plan participants	—			(19,083		)

7

Common unit repurchases	—			(3,650		)
Other	(20		)	(112		)
Net cash provided by financing activities	287,192			155,585
Net decrease in cash and cash equivalents	(4,749		)	(11,250		)
Cash and cash equivalents, beginning of period	28,176			41,303
Cash and cash equivalents, end of period	$	23,427		$	30,053

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

8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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.AtSeptember 30, 2016, our operations include:

• Our Crude Oil Logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests intwocrude oil pipelines,purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

• Our Water Solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities,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 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 its18owned 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, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in27states and the District of Columbia.

• Our Refined Products and Renewables segment, which 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.

Recent Developments

On February 1, 2016, we completed the sale of our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners (“ArcLight”). As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. See Note 2 for a discussion of the sale. As TLP was previously a consolidated entity, our condensed consolidated statements of operations for the three months and six months endedSeptember 30, 2015 included three months and six months, respectively, of TLP’s operations and income attributable to the noncontrolling interests of TLP. On April 1, 2016, we sold all of the TLP common units we owned toArcLight. See Note 2 for a discussion of the sale.

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. We have included 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

9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2016 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2016 included in our Annual Report on Form 10-K (“Annual Report”).

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment.The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction.We have restated our previously issued condensed consolidated statements of operations and condensed consolidated statements of comprehensive loss for the three months andsix months endedSeptember 30, 2015 and condensed consolidated statement of cash flows for the six months endedSeptember 30, 2015. See Note 17in our Annual Reportfor a summary of the impact of the error correction for the three months andsix months endedSeptember 30, 2015.

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, 2017.

Use of Estimates

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

Critical estimates we make in the preparation of our condensed consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations, the 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 various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Significant Accounting Policies

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

Fair Value Measurements

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

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

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

10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our 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 non-cash mark-to-market adjustments) are reported within cost of sales in our 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 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.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues during the three months endedSeptember 30, 2016 and 2015 include $1.2 million and $1.5 million, respectively, and revenues during the six months endedSeptember 30, 2016 and 2015 include $2.5 million and $2.9 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Supplemental Cash Flow Information

Non-cash investing and financing activities and supplemental disclosures of cash flow information are as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Value of common units issued in business combinations	$	3,969	$	—	$	3,969	$	11,367
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash interest paid	$	29,711	$	26,323	$	58,869	$	57,495
Income taxes paid (net of income tax refunds)	71		533		1,755		4,616

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

Inventories

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

Inventories consist of the following at the dates indicated:

	September 30, 2016		March 31, 2016
	(in thousands)
Crude oil	$	86,495	$	84,030
Natural gas liquids:
Propane	73,704		28,639
Butane	44,929		8,461
Other	5,936		6,011
Refined products:
Gasoline	126,821		80,569
Diesel	138,245		99,398
Renewables	34,328		52,458
Other	9,882		8,240
Total	$	520,340	$	367,806

12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are 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 condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our condensed consolidated statements of cash flows.

On April 1, 2016, we sold all of the TLP common units we owned toArcLightfor approximately$112.4 millionin cash and recorded a gain on disposal of$104.1 millionduring thesix months endedSeptember 30, 2016.

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

Entity	Segment	Ownership Interest	Date Acquired or Formed	September 30, 2016		March 31, 2016
				(in thousands)
Glass Mountain (1)	Crude Oil Logistics	50%	December 2013	$	174,364	$	179,594
Ethanol production facility	Refined Products and Renewables	19%	December 2013	13,507		12,570
Water treatment and disposal facility	Water Solutions	50%	August 2015	2,235		2,238
Retail propane company	Retail Propane	50%	April 2015	556		972
TLP (2)	Refined Products and Renewables	0%	July 2014	—		8,301
Water supply company (3)	Water Solutions	100%	June 2014	—		15,875
Total				$	190,662	$	219,550

(1) When we acquired Gavilon, LLC, (“Gavilon Energy”), we recorded the investment in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $73.6 million at September 30, 2016. This difference relates primarily to goodwill and customer relationships.

(2) On April 1, 2016, we sold all of the TLP common units we owned.

(3) On June 3, 2016, we acquired the remaining65%ownership interest inthe water supply company, and as a result, the water supply company is now consolidated in our condensed consolidated financial statements (see Note 4).

Other Noncurrent Assets

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

	September 30, 2016		March 31, 2016
	(in thousands)
Loan receivable (1)	$	44,957	$	49,827
Tank bottoms (2)	42,044		42,044
Line fill (3)	35,013		35,060
Other	95,725		49,108
Total	$	217,739	$	176,039

(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) 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 September 30, 2016 and March 31, 2016, tank bottoms held in third party

13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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).

(3) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2016 and March 31, 2016, line fill consisted of 486,473 barrels and 487,104 barrels of crude oil, respectively.

Accrued Expenses and Other Payables

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

	September 30, 2016		March 31, 2016
	(in thousands)
Accrued compensation and benefits	$	19,322	$	40,517
Excise and other tax liabilities	56,147		59,455
Derivative liabilities	31,959		28,612
Accrued interest	19,594		20,543
Product exchange liabilities	7,045		5,843
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	20,454		29,343
Total	$	184,634	$	214,426

Sale of General Partner Interest in TLP

As previously reported, on February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight and 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 and six months endedSeptember 30, 2016, we recognized $7.6 million and $15.1 million, respectively, of the deferred gain in our condensed consolidated statements of operations. Within our 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, $154.4 million, is recorded in other noncurrent liabilities.

Noncontrolling Interests

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

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 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.

Also, as discussed in Note 4, we made certain adjustments during the three months endedSeptember 30, 2016 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the fiscal year ended March 31, 2016.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, “Simplifying the Accounting Adjustments for Measurement-Period Adjustments.” The ASU requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for the Partnership beginning April 1, 2016, and required a prospective method of adoption.

14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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.

Recent Accounting Pronouncements

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

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires a prospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our consolidated financial position or results of operations.

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 determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Note 3—Income (Loss) Per Common Unit

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

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except unit and per unit amounts)
Net (loss) income	$	(66,658	)	$	(6,100	)	$	116,095		$	(31,107	)
Less: Net loss (income) attributable to noncontrolling interests	59			(3,497		)	(5,774		)	(7,847		)
Net (loss) income attributable to NGL Energy Partners LP	(66,599		)	(9,597		)	110,321			(38,954		)
Less: Distributions to preferred unitholders	(8,668		)	—			(12,052		)	—
Less: Net loss (income) allocated to general partner (1)	45			(16,185		)	(158		)	(31,559		)
Net (loss) income allocated to common unitholders	$	(75,222	)	$	(25,782	)	$	98,111		$	(70,513	)
Basic (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.93		$	(0.67	)
Diluted (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.91		$	(0.67	)
Basic weighted average common units outstanding	106,186,389			105,189,463			105,183,556			104,542,427
Diluted weighted average common units outstanding	106,186,389			105,189,463			107,997,549			104,542,427

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

The diluted weighted average common units outstanding for the six months ended September 30, 2016 included 2,803,436 warrants and 10,621 performance units that were considered dilutive for the period. For the six months endedSeptember 30, 2016 and 2015, the restricted units were considered antidilutive. For the six months ended September 30, 2016, the convertible preferred units were considered antidilutive.

Note 4—Acquisitions

Fiscal Year Ending March 31, 2017

Water Solutions Facilities

During the six months endedSeptember 30, 2016, we acquiredthreewater solutions facilities and paid $26.9 million of cash. In addition, we have recorded contingent consideration liabilities within accrued expenses and other payables and other noncurrent liabilities related to future royalty payments due to the sellers of one of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and percentage of oil revenues, multiplied by the expected disposal volumes and oil revenue for the expected useful life of the facility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of the uncertainty associated with the expected disposal volumes and oil revenue. As of the acquisition date, we recorded a contingent liability of $2.6 million. Also, for one of these facilities, we have recorded a liability for contingent royalty payments. We estimated the contingent royalty payments based on the contracted royalty rate, which is a flat rate per disposal barrel, multiplied by the expected disposal volumes for the expected useful life of the facility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of the uncertainty associated with the expected disposal volumes. As of the acquisition date, we recorded a contingent royalty liability of $8.2 million.

16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these water solutions facilities, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Property, plant and equipment	$	15,021
Goodwill	18,933
Intangible assets	3,878
Current liabilities	(1,239		)
Other noncurrent liabilities	(9,697		)
Fair value of net assets acquired	$	26,896

Goodwill represents a premium paid to expand the number of our disposal sites in an oilfield production basin currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in this oilfield production basin. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Acquisition of Remaining Interest in Water Solutions Facilities

On September 15, 2016, we acquired the remaining25%ownership interest inthreewater solutions facilities and paid $10.0 million of cash. 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 25% interest had a carrying value of $7.4 million.

Water Pipeline Company

As discussed below, on January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas. On June 3, 2016, we acquired an additional24.5%interest in this water pipeline company as part of the purchase and sale agreement discussed in Note 15. As we control this entity (and continue to retain our controlling financial interest), the acquisition of the additional 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 24.5% interest had a carrying value of $5.2 million.

Water Supply Company

On June 3, 2016, we acquired the remaining65%ownership interest ina water supply company (see Note 2). In exchange for this additional interest, we paid $1.0 million of cash and assumed an outstanding note payable, which relates to money this entity previously borrowed from us. Prior to the completion of this transaction, we accounted for our previously held35% ownership interest of this water supply company using the equity method of accounting (see Note 2). As we now own a controlling interest in this entity, we revalued our previously held35%ownership interest to fair value of $0.8 millionand recorded a loss of$14.9 million, which is recorded within revaluation of investments in our condensed consolidated statement of operations. 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 gain on bargain purchase of$0.6 million within revaluation of investments in our condensed consolidated statement of operations.

17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	1,713
Property, plant and equipment	8,874
Intangible asset	14,472
Current liabilities	(2,765		)
Notes payable-intercompany	(19,900		)
Fair value of net assets acquired	$	2,394

Retail Propane Businesses

During the six months endedSeptember 30, 2016, we acquired threeretail propane businesses and paid $72.1 million of cash and issued 218,617 common units, valued at $4.0 million, in exchange for these assets and operations. In connection with the issuance of the common units, we issued 219 general partner units to our general partner and less than $0.1 million in order to maintain its 0.1% general partner interest in us. The agreement for these acquisitions contemplate post-closing payments for certain working capital items.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	6,282
Property, plant and equipment	30,576
Goodwill	9,419
Intangible assets	36,950
Current liabilities	(5,555		)
Other noncurrent liabilities	(1,587		)
Fair value of net assets acquired	$	76,085

Fiscal Year Ended March 31, 2016

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 value of the assets acquired and liabilities assumed in a business combination.

Water Pipeline Company

During the six months endedSeptember 30, 2016, we finalized the purchase price accounting for the 57.125% interest acquired in a water pipeline company on January 7, 2016. During the three months ended June 30, 2016, we recorded an adjustment to reclassify approximately $1.1 million from property, plant and equipment to intangible assets, in order to present the fair value of the acquired rights-of-way as an indefinite-lived asset, which is consistent with our historical accounting policies. During the six months endedSeptember 30, 2016, we recorded an adjustment of $0.3 million to other noncurrent liabilities to recognize an asset retirement obligation related to assets that we acquired. This adjustment also increased goodwill by the same amount. There have been no other adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

Delaware BasinWater Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for the four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas we acquired on August 24, 2015. There have been no adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

18

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Water Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for nine water facilities acquired under the development agreement during the fiscal year ended March 31, 2016. During the three months ended June 30, 2016, we received additional information and recorded an adjustment of $0.7 million to property, plant and equipment to recognize the fair value of additional assets that we acquired. This adjustment also reduced goodwill by the same amount. In addition, we paid $1.0 million in cash to the seller during the three months ended June 30, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

Retail PropaneBusinesses

During the six months endedSeptember 30, 2016, we finalized the purchase price accounting for five retail propane businesses we acquired during the fiscal year ended March 31, 2016 and paid $0.3 million in cash to a seller during the six months endedSeptember 30, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

Note 5—Property, Plant and Equipment

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

Description	Estimated Useful Lives	September 30, 2016			March 31, 2016
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	168,754		$	169,758
Refined products terminal assets and equipment	20 years	6,844			6,844
Retail propane equipment	2–30 years	227,442			201,312
Vehicles and railcars	3–25 years	194,291			185,547
Water treatment facilities and equipment	3–30 years	535,255			508,239
Crude oil tanks and related equipment	2–40 years	140,245			137,894
Barges and towboats	5–40 years	89,973			86,731
Information technology equipment	3–7 years	42,218			38,653
Buildings and leasehold improvements	3–40 years	123,005			118,885
Land		50,132			47,114
Tank bottoms		20,105			20,355
Other	3–30 years	56,450			11,699
Construction in progress		425,066			383,032
		2,079,780			1,916,063
Accumulated depreciation		(324,364		)	(266,491		)
Net property, plant and equipment		$	1,755,416		$	1,649,572

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Depreciation expense	$	28,703	$	34,469	$	56,357	$	70,264
Capitalized interest expense	1,069		549		4,804		690

19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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

	September 30, 2016			March 31, 2016
Product	Volume (in barrels) (in thousands)	Value (in thousands)		Volume (in barrels) (in thousands)	Value (in thousands)
Crude oil	229	$	19,120	231	$	19,348
Other	24	985		24	1,007
Total		$	20,105		$	20,355

Loss on Disposal of Assets

During the three months and six months endedSeptember 30, 2016, we recorded losses of $8.5 million and $10.8 million, respectively, due primarily to the sales and write-down of certain assets in our Crude Oil Logistics and Water Solutions segments. During the three months and six months endedSeptember 30, 2015, we recorded losses of $1.1 million and $1.7 million, respectively, primarily due to the sales of certain assets in our Crude Oil Logistics and Water Solutions segments. These losses are reported within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statements of operations.

Note 6—Goodwill

The following table summarizes changes in goodwill by segment during the six months endedSeptember 30, 2016:

	Crude Oil Logistics		Water Solutions			Liquids		Retail Propane			Refined Products and Renewables		Total
	(in thousands)
Balances at March 31, 2016	$	579,846	$	290,915		$	266,046	$	127,428		$	51,127	$	1,315,362
Revisions to acquisition accounting (Note 4)	—		(419		)	—		(2		)	—		(421		)
Acquisitions (Note 4)	—		18,933			—		9,419			—		28,352
Adjustment to initial impairment estimate	—		124,662			—		—			—		124,662
Balances at September 30, 2016	$	579,846	$	434,091		$	266,046	$	136,845		$	51,127	$	1,467,955

Goodwill Adjustment to Initial Impairment Estimate

During the three months ended March 31, 2016, we recorded a preliminary goodwill impairment charge of $380.2 million. During the three months ended June 30, 2016, we finalized our goodwill impairment analysis, with the assistance of a third party valuation firm. As a result of finalizing our analysis, we determined that we needed to reverse $124.7 million of the previously recorded goodwill impairment recorded during the three months ended March 31, 2016. The reversal was due primarily to the change in the fair value of our customer relationship intangible assets. With the assistance of the third party valuation firm, inputs such as revenue growth rates and attrition rates related to existing customers were refined and resulted in a lower fair value allocated to customer relationships than in our preliminary calculation. We recorded the reversal within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations.

20

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Note 7—Intangible Assets

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

		September 30, 2016						March 31, 2016
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	883,896	$	274,111	$	609,785	$	852,118	$	233,838	$	618,280
Pipeline capacity rights	30 years	161,589		8,957		152,632		119,636		6,559		113,077
Water facility development agreement	5 years	—		—		—		14,000		7,700		6,300
Executory contracts and other agreements	2–30 years	22,713		19,699		3,014		23,920		21,075		2,845
Non-compete agreements	2–32 years	31,784		15,101		16,683		20,903		13,564		7,339
Trade names	1–10 years	15,439		12,882		2,557		15,439		12,034		3,405
Debt issuance costs (1)	3 years	39,977		25,564		14,413		39,942		22,108		17,834
Total amortizable		1,155,398		356,314		799,084		1,085,958		316,878		769,080
Non-amortizable:
Customer commitments		310,000		—		310,000		310,000		—		310,000
Rights-of-way and easements		47,721		—		47,721		47,190		—		47,190
Water rights		14,472		—		14,472		—		—		—
Trade names		18,870		—		18,870		22,620		—		22,620
Total non-amortizable		391,063		—		391,063		379,810		—		379,810
Total		$	1,546,461	$	356,314	$	1,190,147	$	1,465,768	$	316,878	$	1,148,890

(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.

The weighted-average remaining amortization period for intangible assets is approximately 8.6 years.

Write off of Intangible Assets

As a result of terminating the development agreement in the Water Solutions segment (see Note 15), we incurred a loss of $5.8 million to write off the water facility development agreement. During thesix months endedSeptember 30, 2016, we wrote-off$5.2 millionrelated to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis (see Note 6). These losses are reported within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations.

Amortization expense is as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
Recorded In	2016		2015		2016		2015
	(in thousands)
Depreciation and amortization	$	21,900	$	22,291	$	43,152	$	46,328
Cost of sales	1,749		1,700		3,345		3,401
Interest expense	1,731		1,470		3,456		2,954
Total	$	25,380	$	25,461	$	49,953	$	52,683

21

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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

Year Ending March 31,
2017 (six months)	$	51,028
2018	98,717
2019	89,701
2020	82,185
2021	69,422
Thereafter	408,031
Total	$	799,084

Note 8—Long-Term Debt

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

	September 30, 2016							March 31, 2016
	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	$	1,312,000	$	—		$	1,312,000	$	1,229,500	$	—		$	1,229,500
Working capital borrowings	710,500		—			710,500		618,500		—			618,500
5.125% Notes due 2019	383,467		(3,871		)	379,596		388,467		(4,681		)	383,786
6.875% Notes due 2021	369,063		(6,433		)	362,630		388,289		(7,545		)	380,744
6.650% Notes due 2022	250,000		(3,055		)	246,945		250,000		(3,166		)	246,834
Other long-term debt	59,506		(123		)	59,383		61,488		(108		)	61,380
	3,084,536		(13,482		)	3,071,054		2,936,244		(15,500		)	2,920,744
Less: Current maturities	8,046		—			8,046		7,907		—			7,907
Long-term debt	$	3,076,490	$	(13,482	)	$	3,063,008	$	2,928,337	$	(15,500	)	$	2,912,837

(1) Debt issuance costs related to the Revolving Credit Facility (as defined herein) 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 our notes due in 2019, 2021 and 2022 and other long-term debt was $1.0 million and $0.8 million during the three months endedSeptember 30, 2016 and 2015, respectively, and $1.8 million and $1.6 million during the six months ended September 30, 2016 and 2015, respectively.

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

Year Ending March 31,
2017 (six months)	$	1,619
2018	3,229
2019	3,226
2020	2,236
2021	1,827
Thereafter	1,345
Total	$	13,482

22

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at September 30, 2016. At that date, we had outstanding borrowings of$1.312 billionon the Expansion Capital Facility.The Working Capital Facility had a total capacity of$1.038 billionfor cash borrowings and letters of credit atSeptember 30, 2016. At that date, we had outstanding borrowings of$710.5 millionand outstanding letters of credit of $75.3 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50%to1.75%per year or (ii) an adjusted LIBOR rate plus a margin of1.50%to2.75% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At September 30, 2016, the borrowings under the Credit Agreement had an average interest rateof2.83%, calculated as the LIBOR rate of0.53%plus a margin of2.25%for LIBOR borrowings and the prime rate of3.50%plus a margin of1.25%on alternate base rate borrowings.AtSeptember 30, 2016, the interest rate in effect on letters of credit was2.25%. Commitment fees are charged at a rate ranging from0.38%to0.50% on any unused capacity.

The Revolving Credit Facility is secured by substantially all of our assets. The Credit Agreement also specifies that our leverage ratio cannot be more than4.75to1 and that our interest coverage ratio cannot be less than2.75to1at any quarter end.AtSeptember 30, 2016, our leverage ratio was approximately4.15to1and our interest coverage ratio was approximately4.60to1.

At September 30, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued$400.0 millionof5.125% Senior Notes Due 2019 (the “2019 Notes”). During thethree months ended June 30, 2016, we repurchased$5.0 millionof our 2019 Notes for an aggregate purchase price of$3.1 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of$1.8 million(net of the write off of debt issuance costs of$0.1 million).

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued$450.0 millionof6.875%Senior Notes Due 2021 (the “2021 Notes”). During thethree months ended June 30, 2016,we repurchased$19.2 millionof our 2021 Notes for an aggregate purchase price of$12.0 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of$6.8 million(net of the write off of debt issuance costs of$0.4 million).

23

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued$250.0 millionof Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of$25.0 millionbeginning on December 19, 2017 and ending on the maturity date of June 19, 2022.We have the option to prepay outstanding principal, although we would incur a prepayment penalty.On September 30, 2016, we amended our Note Purchase Agreement which, among other things, changes the maximum allowable leverage ratio to match the maximum allowable leverage ratio and the calculation of such ratio under our Credit Agreement. Additionally, the amendment provides for an increase in interest charged should our leverage ratio exceed certain predetermined levels. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

AtSeptember 30, 2016, we were in compliance with the covenants under the Note Purchase Agreement.

Other Long-Term Debt

We have certain notes payable related to equipment financing. We have also executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. These instruments have a combined principal balance of $59.5 million at September 30, 2016, and the interest rates on these instruments range from 1.17% to 7.08% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at September 30, 2016:

Year Ending March 31,	Revolving Credit Facility		2019 Notes		2021 Notes		2022 Notes		Other Long-Term Debt		Total
	(in thousands)
2017 (six months)	$	—	$	—	$	—	$	—	$	3,405	$	3,405
2018	—		—		—		25,000		8,014		33,014
2019	2,022,500		—		—		50,000		6,857		2,079,357
2020	—		383,467		—		50,000		6,372		439,839
2021	—		—		—		50,000		34,728		84,728
Thereafter	—		—		369,063		75,000		130		444,193
Total	$	2,022,500	$	383,467	$	369,063	$	250,000	$	59,506	$	3,084,536

Note 9—Income Taxes

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

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2013 to 2016 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years

24

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our condensed consolidated financial statements at September 30, 2016 or March 31, 2016.

Note 10—Commitments and Contingencies

Legal Contingencies

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

Environmental Matters

Our condensed consolidated balance sheet at September 30, 2016 includes a liability, measured on an undiscounted basis, of $2.2 million related to environmental matters, which is reported within accrued expenses and other payables. Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (hereafter referred to as “Gavilon”) of alleged violations in 2011 by Gavilon of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by NGL 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 and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint relates to transactions between Gavilon and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon in 2011. The complaint seeks an order declaring that the RINs generated by Western Dubuque be declared invalid, that the defendants retire and replace such RINs and that the defendants pay statutory civil penalties. Consistent with our position against the previous EPA allegations, we deny the allegations in this civil complaint and intend to vigorously defend ourselves in the civil action. However, at this time NGL is unable to determine the outcome of this action or its significance to us.

25

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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 is a rollforward of our asset retirement obligation, which is reported within other noncurrent liabilities in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2016	$	5,574
Liabilities assumed in acquisitions	406
Accretion expense	207
Balance at September 30, 2016	$	6,187

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

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	67,837
2018	122,935
2019	101,047
2020	90,112
2021	80,457
Thereafter	135,486
Total	$	597,874

Rental expense relating to operating leases was $27.0 million and $33.3 million during the three months endedSeptember 30, 2016 and 2015, respectively, and $56.9 million and $67.1 million during the six months ended September 30, 2016 and 2015, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. The following table summarizes future minimum throughput payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	26,008
2018	52,082
2019	52,170
2020	42,418
Total	$	172,678

26

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods. The following table summarizes such commitments at September 30, 2016:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	35,592	$	18,710
Natural gas liquids index-price (gallons)	587,044	347,020
Crude oil fixed-price (barrels)	1,993	88,079
Crude oil index-price (barrels)	14,466	655,273
Sale commitments:
Natural gas liquids fixed-price (gallons)	163,546	105,868
Natural gas liquids index-price (gallons)	414,042	317,983
Crude oil fixed-price (barrels)	3,415	152,584
Crude oil index-price (barrels)	12,953	637,731

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (as discussed in Note 12) or inventory positions (as discussed 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 condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $41.0 million of our prepaid expenses and other current assets and $29.6 million of our accrued expenses and other payables at September 30, 2016.

Note 11—Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner 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.

Our Distributions

The following table summarizes distributions declared for the last three 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 21, 2016	May 3, 2016	May 13, 2016	$	0.3900	$	40,626	$	70
July 22, 2016	August 4, 2016	August 12, 2016	0.3900		41,146		71
October 20, 2016	November 4, 2016	November 14, 2016	0.3900		41,907		72

Class A Convertible Preferred Units

On April 21, 2016, we entered into a private placement agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. and its co-investors (“Oaktree”). On June 23, 2016, the private placement agreement was amended to increase the aggregate principal amount from $200 million to $240

27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

million. On May 11, 2016, we received an initial $100 million (“initial closing date”) and Oaktree received 8,309,237 Preferred Units, and on June 24, 2016, we received the remaining $140 million (“second closing date”) and Oaktree received 11,632,932 Preferred Units. In addition, Oaktree received 4,375,112 warrants (1,822,963 at the initial closing date and 2,552,149 at the second closing date) to purchase common units at an exercise price of $0.01 per common unit.

We will pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Preferred Units then outstanding in cash, to the extent declared by the board of directors of our general partner. To the extent declared, such distributions will be paid for each such quarter within 45 days after each quarter end. On July 22, 2016, we declared a pro rata distribution for the three months ended June 30, 2016 of $1.8 million which was paid to the holders of the Preferred Units on August 12, 2016. On October 20, 2016, we declared a distribution for the three months ended September 30, 2016 of $6.4 million to be paid to the holders of the Preferred Units on November 14, 2016.

If the Preferred Unit quarterly distribution is not made in full in cash for any quarter, the Preferred Unit distribution rate will increase by one quarter of a percentage point (0.25%) per annum beginning with distributions for the first six-month period that a payment default is in effect, and will further increase by an additional one quarter of a percentage point (0.25%) beginning with distributions for the next six-month period during which a payment default remains in effect. The deficiency rate shall not exceed 11.25% per annum; as long as the default is occurring, the amount of accrued but unpaid Preferred Unit quarterly distributions shall increase at an annual rate of 10.75%, compounded quarterly, until paid in full.

The Preferred Units have no mandatory redemption date but are redeemable, at our election, any time after the first anniversary of the closing date. We have the right to redeem all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the redemption multiple then in effect. The redemption multiple means (a) 140% for redemptions occurring on or after the first, but prior to the second anniversary of the closing date, (b) 115% for the redemptions occurring on or after the second, but prior to the third anniversary of the closing date, (c) 110% for redemptions occurring on or after the third, but prior to the eighth anniversary of the closing date and (d) 101% for redemptions occurring on or after the eighth anniversary of the closing date.

At any time after the third anniversary of the initial closing date, the Preferred Unit holders shall have the right to convert all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the conversion multiple then in effect, which may be settled in common units, cash or a combination, at our discretion. The conversion multiple means if our common units are trading at or above $12.035 (“the initial conversion price”), the conversion price is not adjusted. However, if the conversion price is less than the initial conversion price, the conversion price will be reset to the greater of (i) the adjusted volume weighted average price of our common units for the fifteen trading days immediately preceding the third anniversary of the closing date or (ii) $5.00.

Upon a change of control of the Partnership, each Preferred Unit holder shall have the right, at its election, to either (i) elect to have its Preferred Units converted to common units; (ii) if we are the surviving entity of such change of control, it can elect to continue to hold its Preferred Units; or (iii) require us to redeem its Preferred Units for cash equal to (a) prior to the first anniversary of the closing date, 140% of the unit purchase price; (b) on or after the first but prior to the second anniversary of the closing date, 130% of the unit purchase price; (c) on or after the second anniversary of the closing date, 120% of the unit purchase price; and (d) thereafter, 101% of the unit purchase price. In each case, this amount will include any accrued but unpaid distributions at the redemption date.

Under the private placement agreement, we are required to file within 180 days of the initial closing date a registration statement registering the resales of common units issued or to be issued upon conversion of the Preferred Units or exercise of the warrants and have the registration statement declared effective within 360 days after the closing date. We are required to continue to maintain the effectiveness of the registration statement until all securities have been sold. If the registration statement is not effective before the deadline, then the Preferred Unit holders shall be entitled to liquidated damages. The liquidated damages, which would accrue daily, are an amount equal to 0.25% of the multiplier for the first 60 day period following the effectiveness deadline plus an additional 0.25% of the multiplier for each subsequent 30 day period (i.e. 0.50% for 61-90 days, 0.75% for 91-120 days and 1.00% thereafter) up to a maximum of 1.00% of the liquidated damage multiplier per 30 day period, until the registration statement becomes effective or the Preferred Units are sold.

The warrants have an eight year term, after which unexercised warrants will expire. 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 of the original issue date and the final one-third may be converted from and after the

28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

third anniversary. Upon a change of control or in the event we exercise our redemption right with respect to the Preferred Units, all unvested warrants shall immediately vest and be exercisable in full.

We received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of Preferred Units and warrants. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units ($186.4 million), which includes the value of the beneficial conversion feature, and warrants ($48.6 million). As discussed below, $131.5 million of the amount allocated to the Preferred Units is allocated to the intrinsic value of a beneficial conversion feature. A beneficial conversion feature is defined as a nondetachable conversion feature that is in the money at the commitment date. Per the applicable accounting guidance, we are required to allocate a portion of the proceeds allocated to the Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per share value of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We record the accretion attributed to the beneficial conversion feature as a deemed distribution using the effective interest method over the three year period prior to the effective dates of the holders’ conversion right. Accretion for the beneficial conversion feature was $2.2 million for the three months endedSeptember 30, 2016 and $3.8 million for the six months ended September 30, 2016.

As discussed above, the Preferred Units are not mandatorily redeemable but are redeemable upon a change of control, which was not certain to occur at the issuance of the Preferred Units. Due to the redemption being conditioned upon an event that is not certain to occur or that is not under our control, we are required to record the value allocated to the Preferred Units, excluding the value of the beneficial conversion feature, between liabilities and equity (mezzanine or temporary equity) within our condensed consolidated balance sheet. The value allocated to the warrants and the beneficial conversion feature were recorded as part of Limited Partners’ equity within our condensed consolidated balance sheet.

Amended and Restated Partnership Agreement

On June 24, 2016, NGL Energy Holdings LLC executed the Third Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Preferred Units are defined in the amended and restated partnership agreement. The 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. The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless redeemed by the Partnership or converted into common units at the election of the Partnership or the Preferred Unit holders or in connection with a change of control.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with anat-the-market program (the “ATM Program”)pursuant to which we may issue and sell common units for up to$200.0 millionin gross proceeds.This ATM Program is registered with the SEC on an effective registration statement on Form S-3.During thethree months endedSeptember 30, 2016, we sold524,000common units for proceeds of$9.6 million, net of offering costs ofless than $0.1 million. In connection with the issuance of the common units, we issued524general partner units to our general partner andless than $0.1 millionin order to maintain its0.1%general partner interest in us. As of September 30, 2016, approximately $190.4 million remained available for sale under the Partnership’s ATM Program.

Subsequent to September 30, 2016, we sold an additional192,000common units for proceeds of$3.7 million, net of offering costs ofless than $0.1 million.

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 in the event of a change in 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.

29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

During the three months ended September 30, 2016, we changed our process for how taxes are withheld upon the vesting of restricted units. Previously, employees could choose to pay cash for their portion of the taxes or have us withhold enough units to meet their tax withholding requirements. Employees could also elect to have the units withheld to exceed the statutory minimums. Now, employees will still be able to pay cash to satisfy their tax obligation or they can elect to sell enough units, through a broker assisted cashless exercise program, to meet their tax obligation. As a result of this change in process, the unvested restricted units and future grants are eligible for equity classification. Prior to this change in process, we classified any Service Awards or Performance Awards granted as liabilities and were required to recalculate the fair value of the award at each reporting date. Awards classified as equity are valued only at their grant date and are not revalued at each reporting date. As of June 30, 2016, we had liabilities related to our Service Awards and Performance Awards of $25.6 million and $1.8 million, respectively, which we reclassified to equity.

The following table summarizes the Service Award activity during the six months endedSeptember 30, 2016:

Unvested Service Award units at March 31, 2016	2,297,132
Units granted	3,048,100
Units vested and issued	(2,340,082	)
Units forfeited	(322,100	)
Unvested Service Award units at September 30, 2016	2,683,050

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

Year Ending March 31,
2017 (six months)	10,000
2018	887,350
2019	894,800
Thereafter	890,900
Unvested Service Award units at September 30, 2016	2,683,050

Service Awards are valued at the market price as of the date of grant 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 must at least equal the portion of the grant-date value of the award that is vested at that date. During the three months endedSeptember 30, 2016 and 2015, we recorded compensation expense related to Service Award units of $25.8 million and $14.9 million, respectively. During the six months endedSeptember 30, 2016 and 2015, we recorded compensation expense related to Service Award units of $46.7 million and $33.4 million, respectively.

Of the restricted units granted and vested during the six months endedSeptember 30, 2016, 1,008,091 units were granted as a bonus for performance during the fiscal year ended March 31, 2016. We accrued expense of $16.8 million during the fiscal year ended March 31, 2016 as an estimate of the value of such bonus units that would be granted. During the six months endedSeptember 30, 2016, we recorded an additional $2.2 million to true up the estimate to the $19.0 million of actual expense associated with these bonuses. Since the units were not formally granted until August 2016, the full $19.0 million is reflected in the expense during the three months and six months ended September 30, 2016 in the amounts in the preceding paragraph above.

30

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	9,329
2018	12,239
2019	8,853
Thereafter	2,317
Total	$	32,738

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 September 30, 2016, 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

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

Our Relative Total Unitholder Return Percentile Ranking	Payout (% of Target Units)
Less than 50th percentile	0%
Between the 50th and 75th percentile	50%–100%
Between the 75th and 90th percentile	100%–200%
Above the 90% percentile	200%

The following table summarizes the Performance Award activity during the six months ended September 30, 2016:

Unvested Performance Award units at March 31, 2016	637,382
Units granted	932,309
Units forfeited	(380,691	)
Unvested Performance Award units at September 30, 2016	1,189,000

During the July 1, 2013 through June 30, 2016 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 units vested on July 1, 2016 and are considered to be forfeited.

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. During the three months ended September 30, 2016 and 2015, we recorded compensation expense related to Performance Award units of $1.6 million and $0.3 million, respectively. During the six months ended September 30, 2016 and 2015, we recorded compensation expense related to Performance Award units of $3.1 million and $18.1 million, respectively.

31

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	4,138
2018	6,197
2019	3,232
Thereafter	655
Total	$	14,222

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the LTIP plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2016, approximately 1.1 million common units remain available for issuance under the LTIP.

Note 12—Fair Value of Financial Instruments

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

Commodity Derivatives

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

	September 30, 2016						March 31, 2016
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	2,512		$	(40,260	)	$	47,361		$	(3,983	)
Level 2 measurements	42,455			(32,253		)	32,700			(28,612		)
	44,967			(72,513		)	80,061			(32,595		)
Netting of counterparty contracts (1)	(3,091		)	3,091			(3,384		)	3,384
Net cash collateral provided (held)	21			37,463			(18,176		)	599
Commodity derivatives in condensed consolidated balance sheet	$	41,897		$	(31,959	)	$	58,501		$	(28,612	)

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

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

	September 30, 2016			March 31, 2016
	(in thousands)
Prepaid expenses and other current assets	$	41,897		$	58,501
Accrued expenses and other payables	(31,959		)	(28,612		)
Net commodity derivative asset	$	9,938		$	29,889

32

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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 September 30, 2016:
Cross-commodity (1)	October 2016–March 2017	126		$	1,465
Crude oil fixed-price (2)	October 2016–December 2016	(588	)	(3,041		)
Propane fixed-price (2)	October 2016–December 2017	462		518
Refined products fixed-price (2)	October 2016–September 2017	(5,628	)	(22,607		)
Other	October 2016–March 2022			(3,881		)
				(27,546		)
Net cash collateral provided				37,484
Net commodity derivative asset in condensed consolidated balance sheet				$	9,938
At March 31, 2016:
Cross-commodity (1)	April 2016–March 2017	251		$	1,663
Crude oil fixed-price (2)	April 2016–December 2016	(1,583	)	(3,655		)
Propane fixed-price (2)	April 2016–December 2017	540		(592		)
Refined products fixed-price (2)	April 2016–June 2017	(5,355	)	48,557
Other	April 2016–March 2017			1,493
				47,466
Net cash collateral held				(17,577		)
Net commodity derivative asset in condensed consolidated balance sheet				$	29,889

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

(2) 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 and six months endedSeptember 30, 2016, we recorded a net gain of $14.7 million and a net loss of $45.0 million, respectively, and during the three months and six months endedSeptember 30, 2015, we recorded net gains of $85.8 million and $44.5 million, respectively, from our commodity derivatives to cost of sales.

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. AtSeptember 30, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our condensed consolidated balance sheets and recognized in our net income.

33

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates.AtSeptember 30, 2016, we had$2.0 billionof outstanding borrowings under our Revolving Credit Facility at an average interest rate of2.83%.

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2016 (in thousands):

2019 Notes	$	360,459
2021 Notes	349,995
2022 Notes	253,838

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by 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.

Note 13—Segments

The following table summarizes certain financial data related to our segments for the periods indicated. 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.

34

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	341,981		$	997,106		$	756,600		$	2,309,889
Crude oil transportation and other	9,172			12,746			22,106			31,695
Elimination of intersegment sales	(1,268		)	(2,274		)	(2,870		)	(6,222		)
Total Crude Oil Logistics revenues	349,885			1,007,578			775,836			2,335,362
Water Solutions:
Service fees	28,528			35,203			54,225			71,941
Recovered hydrocarbons	5,681			10,746			12,877			26,564
Other revenues	5,524			1,545			8,384			3,282
Total Water Solutions revenues	39,733			47,494			75,486			101,787
Liquids:
Propane sales	101,613			98,770			198,084			204,260
Other product sales	135,700			160,836			249,435			308,347
Other revenues	8,075			10,122			15,222			19,622
Elimination of intersegment sales	(11,128		)	(10,736		)	(23,432		)	(24,252		)
Total Liquids revenues	234,260			258,992			439,309			507,977
Retail Propane:
Propane sales	36,170			36,119			77,811			79,304
Distillate sales	5,589			7,678			16,044			20,625
Other revenues	9,331			9,409			17,638			17,724
Elimination of intersegment sales	—			—			(16		)	—
Total Retail Propane revenues	51,090			53,206			111,477			117,653
Refined Products and Renewables:
Refined products sales	2,274,715			1,704,259			4,151,572			3,413,208
Renewables sales	95,830			93,189			202,312			199,342
Service fees	(121		)	28,739			11,145			56,812
Elimination of intersegment sales	(102		)	(262		)	(144		)	(477		)
Total Refined Products and Renewables revenues	2,370,322			1,825,925			4,364,885			3,668,885
Corporate and Other	248			—			515			—
Total revenues	$	3,045,538		$	3,193,195		$	5,767,508		$	6,731,664
Depreciation and Amortization:
Crude Oil Logistics	$	9,025		$	10,053		$	17,993		$	20,055
Water Solutions	25,129			22,416			49,563			43,262
Liquids	4,425			2,745			8,874			7,749
Retail Propane	10,705			8,909			20,392			17,615
Refined Products and Renewables	416			11,152			833			25,327
Corporate and Other	903			1,486			1,854			2,584
Total depreciation and amortization	$	50,603		$	56,761		$	99,509		$	116,592
Operating Income (Loss):
Crude Oil Logistics	$	(19,039	)	$	(75	)	$	(19,664	)	$	11,885
Water Solutions	(4,430		)	18,257			75,034			28,704
Liquids	8,384			20,370			8,327			19,899
Retail Propane	(8,717		)	(1,765		)	(11,219		)	(2,465		)
Refined Products and Renewables	11,387			(5,244		)	161,156			27,776
Corporate and Other	(23,413		)	(13,245		)	(55,562		)	(68,711		)
Total operating (loss) income	$	(35,828	)	$	18,298		$	158,072		$	17,088

35

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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 September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Crude Oil Logistics	$	32,397	$	44,384	$	104,702	$	107,023
Water Solutions	25,237		72,531		68,353		133,020
Liquids	6,693		18,886		13,161		36,064
Retail Propane	71,425		15,814		77,974		22,709
Refined Products and Renewables	1,143		7,588		1,167		23,283
Corporate and Other	614		—		1,732		1,169
Total	$	137,509	$	159,203	$	267,089	$	323,268

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:

	September 30, 2016		March 31, 2016
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,720,278	$	1,679,027
Water Solutions	1,316,196		1,162,405
Liquids	575,963		572,081
Retail Propane	549,429		483,330
Refined Products and Renewables	219,157		180,783
Corporate and Other	32,495		36,198
Total	$	4,413,518	$	4,113,824
Total assets:
Crude Oil Logistics	$	2,318,083	$	2,197,113
Water Solutions	1,354,786		1,236,875
Liquids	785,303		693,872
Retail Propane	611,340		538,267
Refined Products and Renewables	904,386		765,806
Corporate and Other	100,020		128,222
Total	$	6,073,918	$	5,560,155

Note 14—Transactions with Affiliates

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

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

Certain members of our management and members of their families 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 six months endedSeptember 30, 2016, $10.5 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

36

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Sales to SemGroup	$	3,513	$	4,593	$	3,584	$	42,031
Purchases from SemGroup	1,938		6,478		3,963		45,303
Sales to equity method investees	95		1,696		500		3,086
Purchases from equity method investees	27,345		24,816		57,992		55,764
Sales to entities affiliated with management	75		91		152		198
Purchases from entities affiliated with management	3,493		16,214		11,736		23,394

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

	September 30, 2016		March 31, 2016
	(in thousands)
Receivables from SemGroup	$	3,401	$	1,166
Receivables from equity method investees	—		14,446
Receivables from entities affiliated with management	139		13
Total	$	3,540	$	15,625

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

	September 30, 2016		March 31, 2016
	(in thousands)
Payables to SemGroup	$	4,015	$	1,823
Payables to equity method investees	1,155		3,947
Payables to entities affiliated with management	1,074		1,423
Total	$	6,244	$	7,193

We also have a loan receivable of $1.7 million at September 30, 2016 from an equity method investee 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.

We had a loan receivable of $22.3 million at March 31, 2016 from an equity method investee. During the three months ended June 30, 2016, we received loan payments of $0.7 million from our investee in accordance with the loan agreement. During thethree months ended June 30, 2016, we recorded an impairment of$1.7 millionrelated to this loan receivable. On June 3, 2016, we acquired the remaining65%ownership interest in this equity method investee (see Note 4) and this loan receivable is now eliminated upon consolidation.

Note 15—Other Matters

Purchase of Pipeline Capacity Allocations

On certain interstate refined product pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historical shipment volumes. During the six months endedSeptember 30, 2016, we paid $42.0 millionto acquire certain refined product pipeline capacity allocations from other shippers on the Colonial pipeline.

Termination of Development Agreement

On June 3, 2016, we entered into a purchase and sale agreement with the counterparty to the development agreement in our Water Solutions segment (as discussed in Note 4). Total cash consideration paid under the agreement was $49.6 million,

37

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

of which $2.1 million was withheld and recorded in accrued expenses and other payables as of June 30, 2016, and in return we received the following:

• Termination of the development agreement (see Note 4);

• Additional interest in the water pipeline company we acquired in January 2016 (see Note 4);

• Release of contingent consideration liabilities (see Note 4) attributed to certain of our water treatment and disposal facilities;

• Certain parcels of land and permits to develop saltwater disposal wells and other parcels of land containing water wells and equipment; and

• A two-year non-compete agreement with the counterparty.

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 shall be allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and shall not give rise to goodwill or bargain purchase gains. We allocated $1.2 million of the total consideration to property, plant and equipment, $3.3 million to intangible assets, $2.8 million to noncontrolling interest, $25.5 million to the release of contingent consideration liabilities and $16.9 million to the termination of the development agreement. We recorded a $21.3 million gain on the release of $46.8 million of contingent consideration liabilities, which was recorded within gain on early extinguishment of liabilities in our condensed consolidated statement of operations during the six months endedSeptember 30, 2016. For the termination of the development agreement, we recorded a loss of $22.7 million, which included the carrying value of the development agreement asset that was written off (seeNote 7). This loss was recorded within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations during the six months endedSeptember 30, 2016.

Note 16—Subsequent Events

2023 Notes

In October 2016, we issued$700.0 millionof Senior Unsecured Notes (the “2023 Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately$688.0 million, after the initial purchasers’ discount of$10.5 millionand estimated offering costs of$1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The 2023 Notes mature on November 1, 2023 and bear interest at a fixed rate of7.50%, payable on May 1 and November 1 of each year.

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and 2021 Notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP (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 2019 Notes and 2021 Notes. Since NGL Energy Partners LP received the proceeds from the issuance of the 2019 Notes and 2021 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 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

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

38

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

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

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

39

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,116	$	—	$	12,179		$	1,132		$	—		$	23,427
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		585,720			6,354			—			592,074
Accounts receivable-affiliates	—		—		3,540			—			—			3,540
Inventories	—		—		519,795			545			—			520,340
Prepaid expenses and other current assets	—		—		109,969			949			—			110,918
Total current assets	10,116		—		1,231,203			8,980			—			1,250,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,653,011			102,405			—			1,755,416
GOODWILL	—		—		1,448,661			19,294			—			1,467,955
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,166,439			23,708			—			1,190,147
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		190,662			—			—			190,662
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,290,616		—		(1,279,908		)	(10,708		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,689,633		—		96,577			—			(1,786,210		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		1,700			—			—			1,700
OTHER NONCURRENT ASSETS	—		—		217,618			121			—			217,739
Total assets	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918
LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	510,535		$	1,569		$	—		$	512,104
Accounts payable-affiliates	1		—		6,054			189			—			6,244
Accrued expenses and other payables	16,232		—		164,918			3,484			—			184,634
Advance payments received from customers	—		—		87,094			731			—			87,825
Current maturities of long-term debt	—		—		7,252			794			—			8,046
Total current liabilities	16,233		—		775,853			6,767			—			798,853
LONG-TERM DEBT, net of debt issuance costs and current maturities	989,171		—		2,067,264			6,573			—			3,063,008
OTHER NONCURRENT LIABILITIES	—		—		193,213			4,788			—			198,001
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	58,742		—		—			—			—			58,742
EQUITY:
Partners’ equity	1,926,219		—		1,690,096			125,851			(1,815,305		)	1,926,861
Accumulated other comprehensive loss	—		—		(463		)	(179		)	—			(642		)
Noncontrolling interests	—		—		—			—			29,095			29,095
Total equity	1,926,219		—		1,689,633			125,672			(1,786,210		)	1,955,314
Total liabilities, convertible preferred units and equity	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918

40

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	March 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,749	$	—	$	784		$	1,643		$	—		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		516,362			4,652			—			521,014
Accounts receivable-affiliates	—		—		15,625			—			—			15,625
Inventories	—		—		367,250			556			—			367,806
Prepaid expenses and other current assets	—		—		94,426			1,433			—			95,859
Total current assets	25,749		—		994,447			8,284			—			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,568,488			81,084			—			1,649,572
GOODWILL	—		—		1,313,364			1,998			—			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,146,355			2,535			—			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		219,550			—			—			219,550
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,404,479		—		(1,402,360		)	(2,119		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,254,383		—		42,227			—			(1,296,610		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		22,262			—			—			22,262
OTHER NONCURRENT ASSETS	—		—		175,512			527			—			176,039
Total assets	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	417,707		$	2,599		$	—		$	420,306
Accounts payable-affiliates	1		—		7,190			2			—			7,193
Accrued expenses and other payables	16,887		—		196,596			943			—			214,426
Advance payments received from customers	—		—		55,737			448			—			56,185
Current maturities of long-term debt	—		—		7,109			798			—			7,907
Total current liabilities	16,888		—		684,339			4,790			—			706,017
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,011,365		—		1,894,428			7,044			—			2,912,837
OTHER NONCURRENT LIABILITIES	—		—		246,695			541			—			247,236
EQUITY:
Partners’ equity	1,656,358		—		1,254,384			80,090			(1,334,317		)	1,656,515
Accumulated other comprehensive loss	—		—		(1		)	(156		)	—			(157		)
Noncontrolling interests	—		—		—			—			37,707			37,707
Total equity	1,656,358		—		1,254,383			79,934			(1,296,610		)	1,694,065
Total liabilities and equity	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155

41

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,034,053		$	12,118		$	(633	)	$	3,045,538
COST OF SALES	—			—		2,928,036			1,327			(633		)	2,928,730
OPERATING COSTS AND EXPENSES:
Operating	—			—		68,750			4,505			—			73,255
General and administrative	—			—		27,686			240			—			27,926
Depreciation and amortization	—			—		47,740			2,863			—			50,603
Loss (gain) on disposal or impairment of assets, net	—			—		896			(44		)	—			852
Operating (Loss) Income	—			—		(39,055		)	3,227			—			(35,828		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		53			—			—			53
Interest expense	(16,364		)	—		(16,870		)	(291		)	83			(33,442		)
Gain on early extinguishment of liabilities	—			—		938			—			—			938
Other income, net	—			—		2,154			10			(83		)	2,081
(Loss) Income Before Income Taxes	(16,364		)	—		(52,780		)	2,946			—			(66,198		)
INCOME TAX EXPENSE	—			—		(460		)	—			—			(460		)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(50,235		)	—		3,005			—			47,230			—
Net (Loss) Income	(66,599		)	—		(50,235		)	2,946			47,230			(66,658		)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS												59			59
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(8,668		)	(8,668		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												45			45
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(66,599	)	$	—	$	(50,235	)	$	2,946		$	38,666		$	(75,222	)

42

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,153,370		$	49,442		$	(9,617	)	$	3,193,195
COST OF SALES	—			—		3,009,777			5,610			(9,561		)	3,005,826
OPERATING COSTS AND EXPENSES:
Operating	—			—		75,023			22,663			(56		)	97,630
General and administrative	—			—		24,538			4,760			—			29,298
Depreciation and amortization	—			—		45,006			11,755			—			56,761
Loss (gain) on disposal or impairment of assets, net	—			—		1,294			(3		)	—			1,291
Revaluation of liabilities	—			—		(15,909		)	—			—			(15,909		)
Operating Income	—			—		13,641			4,657			—			18,298
OTHER INCOME (EXPENSE):
Equity in (loss) earnings of unconsolidated entities	—			—		(23		)	2,455			—			2,432
Interest expense	(17,913		)	—		(11,351		)	(2,381		)	74			(31,571		)
Other income, net	—			—		1,916			113			(74		)	1,955
(Loss) Income Before Income Taxes	(17,913		)	—		4,183			4,844			—			(8,886		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,793			(7		)	—			2,786
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	8,316			—		1,340			—			(9,656		)	—
Net (Loss) Income	(9,597		)	—		8,316			4,837			(9,656		)	(6,100		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,497		)	(3,497		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,185		)	(16,185		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(9,597	)	$	—	$	8,316		$	4,837		$	(29,338	)	$	(25,782	)

43

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	5,749,034		$	19,469		$	(995	)	$	5,767,508
COST OF SALES	—			—		5,493,864			2,301			(995		)	5,495,170
OPERATING COSTS AND EXPENSES:
Operating	—			—		139,631			8,796			—			148,427
General and administrative	—			—		69,312			485			—			69,797
Depreciation and amortization	—			—		94,049			5,460			—			99,509
Gain on disposal or impairment of assets, net	—			—		(203,443		)	(24		)	—			(203,467		)
Operating Income	—			—		155,621			2,451			—			158,072
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		447			—			—			447
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(32,690		)	—		(30,898		)	(453		)	161			(63,880		)
Gain on early extinguishment of liabilities	8,614			—		22,276			—			—			30,890
Other income, net	—			—		5,990			24			(161		)	5,853
(Loss) Income Before Income Taxes	(24,076		)	—		139,071			2,022			—			117,017
INCOME TAX EXPENSE	—			—		(922		)	—			—			(922		)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	134,397			—		(3,752		)	—			(130,645		)	—
Net Income	110,321			—		134,397			2,022			(130,645		)	116,095
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(5,774		)	(5,774		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(12,052		)	(12,052		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(158		)	(158		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	110,321		$	—	$	134,397		$	2,022		$	(148,629	)	$	98,111

44

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	6,650,251		$	100,621		$	(19,208	)	$	6,731,664
COST OF SALES	—			—		6,333,438			14,022			(19,083		)	6,328,377
OPERATING COSTS AND EXPENSES:
Operating	—			—		160,323			43,022			(125		)	203,220
General and administrative	—			—		81,208			10,571			—			91,779
Depreciation and amortization	—			—		90,545			26,047			—			116,592
Loss (gain) on disposal or impairment of assets, net	—			—		1,715			(3		)	—			1,712
Revaluation of liabilities	—			—		(27,104		)	—			—			(27,104		)
Operating Income	—			—		10,126			6,962			—			17,088
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,872			8,278			—			11,150
Interest expense	(35,714		)	—		(22,344		)	(4,463		)	148			(62,373		)
Other income, net	—			—		691			237			(148		)	780
(Loss) Income Before Income Taxes	(35,714		)	—		(8,655		)	11,014			—			(33,355		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,286			(38		)	—			2,248
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(3,240		)	—		3,129			—			111			—
Net (Loss) Income	(38,954		)	—		(3,240		)	10,976			111			(31,107		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(7,847		)	(7,847		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(31,559		)	(31,559		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	(39,295	)	$	(70,513	)

45

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(66,599	)	$	—	$	(50,235	)	$	2,946	$	47,230	$	(66,658	)
Other comprehensive loss	—			—		(333		)	—		—		(333		)
Comprehensive (loss) income	$	(66,599	)	$	—	$	(50,568	)	$	2,946	$	47,230	$	(66,991	)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net (loss) income	$	(9,597	)	$	—	$	8,316	$	4,837		$	(9,656	)	$	(6,100	)
Other comprehensive loss	—			—		—		(19		)	—			(19		)
Comprehensive (loss) income	$	(9,597	)	$	—	$	8,316	$	4,818		$	(9,656	)	$	(6,119	)

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	110,321	$	—	$	134,397		$	2,022		$	(130,645	)	$	116,095
Other comprehensive loss	—		—		(475		)	(10		)	—			(485		)
Comprehensive income	$	110,321	$	—	$	133,922		$	2,012		$	(130,645	)	$	115,610

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	111	$	(31,107	)
Other comprehensive loss	—			—		—			(27		)	—		(27		)
Comprehensive (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,949		$	111	$	(31,134	)

46

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 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	$	(31,541	)	$	—	$	(12,751	)	$	(12,107	)	$	(56,399	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(158,333		)	(1,347		)	(159,680		)
Purchases of pipeline capacity allocations	—			—		(41,953		)	—			(41,953		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(113,297		)	—			(113,297		)
Cash flows from commodity derivatives	—			—		(25,015		)	—			(25,015		)
Proceeds from sales of assets	—			—		379			17			396
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Distributions of capital from unconsolidated entities	—			—		5,233			—			5,233
Payments on loan for natural gas liquids facility	—			—		4,324			—			4,324
Loan to affiliate	—			—		(1,700		)	—			(1,700		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash used in investing activities	—			—		(234,212		)	(1,330		)	(235,542		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		770,000			—			770,000
Payments on revolving credit facilities	—			—		(595,500		)	—			(595,500		)
Repurchases of senior notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(4,080		)	(343		)	(4,423		)
Debt issuance costs	(255		)	—		(65		)	—			(320		)
Contributions from partners	(442		)	—		—			—			(442		)
Contributions from noncontrolling interest owners	—			—		—			966			966
Distributions to partners	(83,707		)	—		—			—			(83,707		)
Distributions to noncontrolling interest owners	—			—		—			(2,750		)	(2,750		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018			—		—			—			235,018
Proceeds from sale of common units, net of offering costs	9,383			—		—			—			9,383
Payments for the early extinguishment of liabilities	—			—		(25,884		)	—			(25,884		)
Net changes in advances with consolidated entities	(128,960		)	—		113,907			15,053			—
Other	—			—		(20		)	—			(20		)
Net cash provided by financing activities	15,908			—		258,358			12,926			287,192
Net (decrease) increase in cash and cash equivalents	(15,633		)	—		11,395			(511		)	(4,749		)
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	10,116		$	—	$	12,179		$	1,132		$	23,427

47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At September 30, 2016 and March 31, 2016, and for the

Three Months and Six Months Ended September 30, 2016 and 2015

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2015
	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	$	(34,469	)	$	—	$	173,058		$	35,506		$	174,095
INVESTING ACTIVITIES:
Capital expenditures	—			—		(184,680		)	(37,596		)	(222,276		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(150,546		)	—			(150,546		)
Cash flows from commodity derivatives	—			—		43,032			—			43,032
Proceeds from sales of assets	—			—		3,565			2			3,567
Investments in unconsolidated entities	—			—		(2,700		)	(4,226		)	(6,926		)
Distributions of capital from unconsolidated entities	—			—		5,652			2,555			8,207
Loan for natural gas liquids facility	—			—		(3,913		)	—			(3,913		)
Payments on loan for natural gas liquids facility	—			—		3,546			—			3,546
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Net cash used in investing activities	—			—		(301,665		)	(39,265		)	(340,930		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,311,500			43,200			1,354,700
Payments on revolving credit facilities	—			—		(963,000		)	(43,600		)	(1,006,600		)
Payments on other long-term debt	—			—		(2,274		)	(70		)	(2,344		)
Debt issuance costs	49			—		(180		)	(1,249		)	(1,380		)
Contributions from partners	45			—		—			—			45
Contributions from noncontrolling interest owners	—			—		—			6,613			6,613
Distributions to partners	(154,824		)	—		—			—			(154,824		)
Distributions to noncontrolling interest owners	—			—		—			(17,780		)	(17,780		)
Taxes paid on behalf of equity incentive plan participants	—			—		(19,083		)	—			(19,083		)
Common unit repurchases	(3,650		)	—		—			—			(3,650		)
Net changes in advances with consolidated entities	186,776			—		(203,533		)	16,757			—
Other	—			—		(33		)	(79		)	(112		)
Net cash provided by financing activities	28,396			—		123,397			3,792			155,585
Net (decrease) increase in cash and cash equivalents	(6,073		)	—		(5,210		)	33			(11,250		)
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	23,042		$	—	$	4,547		$	2,464		$	30,053

48

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and six months endedSeptember 30, 2016. 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 included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016 (“Annual Report”).

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner.AtSeptember 30, 2016, our operations include:

• Our Crude Oil Logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests intwocrude oil pipelines,purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. During the three months endedSeptember 30, 2016, the segment generated an operating loss of $19.0 million. The segment generated an operating loss of $0.1 million during the three months endedSeptember 30, 2015. During the six months endedSeptember 30, 2016, the segment generated an operating loss of $19.7 million. The segment generated operating income of $11.9 million during the six months endedSeptember 30, 2015.

• Our Water Solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities,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 washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services. During the three months endedSeptember 30, 2016, the segment generated an operating loss of $4.4 million. The segment generated operating income of $18.3 million during the three months endedSeptember 30, 2015. During the six months endedSeptember 30, 2016, the segment generated operating income of $75.0 million, which includes the reversal of $124.7 million of the previously recorded $380.2 million goodwill impairment charge recorded during the three months ended March 31, 2016 (see Note 6 to our condensed consolidated financial statements included in this Quarterly Report). The segment generated operating income of $28.7 million during the six months endedSeptember 30, 2015.

• 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 its18owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah. During the three months ended September 30, 2016, the segment generated operating income of $8.4 million. The segment generated operating income of $20.4 million during the three months ended September 30, 2015. During the six months ended September 30, 2016, the segment generated operating income of $8.3 million. The segment generated operating income of $19.9 million during the six months ended September 30, 2015.

• Our Retail Propane segment sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in27states and the District of Columbia. During the three months ended September 30, 2016, the segment generated an operating loss of $8.7 million. The segment generated an operating loss of $1.8 million during the three months ended September 30, 2015. During the six months ended September 30, 2016, the segment generated an operating loss of $11.2 million. The segment generated an operating loss of $2.5 million during the six months ended September 30, 2015.

• Our Refined Products and Renewables segment, which 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. During the three months endedSeptember 30, 2016, the segment generated operating income of $11.4 million. The segment generated an operating loss of $5.2 million during the three months endedSeptember 30, 2015. During the six months endedSeptember 30, 2016, the segment generated operating income of $161.2 million, which includes a gain of $104.1 million recorded on the sale of all of the TransMontaigne Partners L.P. (“TLP”) common units we owned during the six months endedSeptember 30, 2016. The segment generated operating income of $27.8 million during the six months endedSeptember 30, 2015.

49

Correction of Error

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment.The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction.We have restated our previously issued condensed consolidated statements of operations and condensed consolidated statements of comprehensive loss for the three months andsix months endedSeptember 30, 2015 and condensed consolidated statement of cash flows for the six months endedSeptember 30, 2015. See Note 17 to our consolidated financial statements in our Annual Reportfor a summary of the impact of the error correction for the three months andsix months endedSeptember 30, 2015.

Recent Developments

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with anat-the-market program (the “ATM Program”)pursuant to which we may issue and sell common units for up to$200.0 millionin gross proceeds. See Note 11 to our condensed consolidated financial statements included in this Quarterly Report for a further discussion.

2023 Notes

In October 2016, we issued$700.0 millionof Senior Unsecured Notes (the “2023 Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately$688.0 million, after the initial purchasers’ discount of$10.5 millionand estimated offering costs of$1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The 2023 Notes mature on November 1, 2023 and bear interest at a fixed rate of7.50%, payable on May 1 and November 1 of each year.

Acquisitions

As discussed below, we completed numerous acquisitions during the fiscal year ended March 31, 2016 and the six months endedSeptember 30, 2016. These acquisitions impact the comparability of our results of operations between periods in our current and prior fiscal years.

Fiscal Year Ending March 31, 2017

During the six months endedSeptember 30, 2016, in our Water Solutions segment, we (i) acquiredthreewater solutions facilities, (ii) acquired the remaining25%ownership interest inthreewater solutions facilities, (iii) acquired an additional24.5%interest in an existing produced water pipeline company, and (iv) acquired the remaining 65%ownership interest ina water supply company. During the six months endedSeptember 30, 2016, in our Retail Propane segment, we acquired threeretail propane businesses. See Note 4 to our condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Fiscal Year Ended March 31, 2016

During the fiscal year ended March 31, 2016, in our Water Solutions segment, we (i) acquired a 57.125% interest in an existing water pipeline company and (ii) acquired 20 water solutions facilities and a 50% interest in an additional facility. During the fiscal year ended March 31, 2016, in our Retail Propane segment, we acquired six retail propane businesses. See Note 4 to our condensed consolidated financial statements included in this Quarterly Report for a further discussion.

50

Consolidated Results of Operations

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

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Total revenues	$	3,045,538		$	3,193,195		$	5,767,508		$	6,731,664
Total cost of sales	2,928,730			3,005,826			5,495,170			6,328,377
Operating expenses	73,255			97,630			148,427			203,220
General and administrative expense	27,926			29,298			69,797			91,779
Depreciation and amortization	50,603			56,761			99,509			116,592
Loss (gain) on disposal or impairment of assets, net	852			1,291			(203,467		)	1,712
Revaluation of liabilities	—			(15,909		)	—			(27,104		)
Operating (loss) income	(35,828		)	18,298			158,072			17,088
Equity in earnings of unconsolidated entities	53			2,432			447			11,150
Revaluation of investments	—			—			(14,365		)	—
Interest expense	(33,442		)	(31,571		)	(63,880		)	(62,373		)
Gain on early extinguishment of liabilities	938			—			30,890			—
Other income, net	2,081			1,955			5,853			780
(Loss) income before income taxes	(66,198		)	(8,886		)	117,017			(33,355		)
Income tax (expense) benefit	(460		)	2,786			(922		)	2,248
Net (loss) income	(66,658		)	(6,100		)	116,095			(31,107		)
Less: Net loss (income) attributable to noncontrolling interests	59			(3,497		)	(5,774		)	(7,847		)
Net (loss) income attributable to NGL Energy Partners LP	(66,599		)	(9,597		)	110,321			(38,954		)
Less: Distributions to preferred unitholders	(8,668		)	—			(12,052		)	—
Less: Net loss (income) allocated to general partner	45			(16,185		)	(158		)	(31,559		)
Net (loss) income allocated to common unitholders	$	(75,222	)	$	(25,782	)	$	98,111		$	(70,513	)

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our Water Solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We have expanded our Retail Propane business through numerous acquisitions of retail propane businesses. As previously reported, on February 1, 2016, we sold our general partner interest in TLP.As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. On April 1, 2016, we sold all of the TLP common units that we owned. The results of operations of our Liquids and Retail Propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months and six months endedSeptember 30, 2016 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2017. See the detailed discussion of items affecting operating income (loss) by segment below.

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.

51

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 income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis.Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

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

The following table reconciles net (loss) income to EBITDA and Adjusted EBITDA for the periods indicated:

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Net (loss) income	$	(66,658	)	$	(6,100	)	$	116,095		$	(31,107	)
Less: Net loss (income) attributable to noncontrolling interests	59			(3,497		)	(5,774		)	(7,847		)
Net (loss) income attributable to NGL Energy Partners LP	(66,599		)	(9,597		)	110,321			(38,954		)
Interest expense	33,489			29,520			63,797			58,168
Income tax expense (benefit)	460			(2,805		)	922			(2,284		)
Depreciation and amortization	54,522			53,299			107,102			107,467
EBITDA	21,872			70,417			282,142			124,397
Net unrealized losses (gains) on derivatives	2,293			(6,286		)	3,220			(2,746		)
Inventory valuation adjustment (1)	39,530			9,197			32,693			19,355
Lower of cost or market adjustments	(393		)	414			108			(5,926		)
Loss (gain) on disposal or impairment of assets, net	851			1,294			(203,504		)	1,713
Gain on early extinguishment of liabilities	(938		)	—			(30,890		)	—
Revaluation of investments	—			—			14,365			—
Equity-based compensation expense (2)	10,660			9,448			32,994			49,680
Acquisition expense (3)	724			567			1,161			632
Other (4)	790			(17,447		)	6,909			(30,490		)
Adjusted EBITDA	$	75,389		$	67,604		$	139,198		$	156,615

(1) Amountreflects the difference between the market value of the inventory ofourRefined 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 inNote 11to our condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense

52

accruals for bonuses expected to be paid in common units, whereas the amounts reported inNote 11 to our condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

(3) During the three months and six months endedSeptember 30, 2016and2015, we incurredexpenses related to legal and advisory costs associated with acquisitions.

(4) Amounts for the three months and six months ended September 30, 2016 represent non-cash operating expenses related to our Grand Mesa Pipeline project and adjustments related to noncontrolling interests. Amounts for the three months and six months ended September 30, 2015 represent 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.

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

	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Reconciliation to condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	54,522		$	53,299		$	107,102		$	107,467
Intangible asset amortization recorded to cost of sales	(1,749		)	(1,700		)	(3,345		)	(3,401		)
Depreciation and amortization of unconsolidated entities	(3,789		)	(3,460		)	(6,858		)	(6,930		)
Depreciation and amortization attributable to noncontrolling interests	829			8,622			1,820			19,456
Other	790			—			790			—
Depreciation and amortization per condensed consolidated statements of operations	$	50,603		$	56,761		$	99,509		$	116,592

	Six Months Ended September 30,
	2016			2015
	(in thousands)
Reconciliation to condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	107,102		$	107,467
Amortization of debt issuance costs recorded to interest expense	5,279			4,558
Depreciation and amortization of unconsolidated entities	(6,858		)	(6,930		)
Depreciation and amortization attributable to noncontrolling interests	1,820			19,456
Other	790			—
Depreciation and amortization per condensed consolidated statements of cash flows	$	108,133		$	124,551

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

	Three Months Ended September 30,					Six Months Ended September 30,
	2016			2015		2016		2015
	(in thousands)
Interest expense per EBITDA table	$	33,489		$	29,520	$	63,797	$	58,168
Interest expense attributable to noncontrolling interests	4			1,815		8		3,395
Interest expense attributable to unconsolidated entities	(51		)	236		75		117
Gain on extinguishment of debt of unconsolidated entities	—			—		—		693
Interest expense per condensed consolidated statements of operations	$	33,442		$	31,571	$	63,880	$	62,373

53

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 September 30, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(19,039	)	$	(4,430	)	$	8,384	$	(8,717	)	$	11,387		$	(23,413	)	$	(35,828	)
Depreciation and amortization	9,025			25,129			4,425		10,705			416			903			50,603
Amortization recorded to cost of sales	100			—			195		—			1,454			—			1,749
Net unrealized losses (gains) on derivatives	1,613			(2,193		)	2,734		139			—			—			2,293
Inventory valuation adjustment	—			—			—		—			39,530			—			39,530
Lower of cost or market adjustments	—			—			—		—			(393		)	—			(393		)
Loss (gain) on disposal or impairment of assets, net	8,477			(11		)	17		(65		)	(7,563		)	(3		)	852
Equity-based compensation expense	—			—			—		—			—			10,660			10,660
Acquisition expense	—			—			—		—			—			724			724
Other income, net	145			—			24		139			11			1,762			2,081
Adjusted EBITDA attributable to unconsolidated entities	2,386			46			—		(111		)	782			—			3,103
Adjusted EBITDA attributable to noncontrolling interest	—			(794		)	—		19			—			—			(775		)
Other	790			—			—		—			—			—			790
Adjusted EBITDA	$	3,497		$	17,747		$	15,779	$	2,109		$	45,624		$	(9,367	)	$	75,389

	As Restated
	Three Months Ended September 30, 2015
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(75	)	$	18,257		$	20,370		$	(1,765	)	$	(5,244	)	$	(13,245	)	$	18,298
Depreciation and amortization	10,053			22,416			2,745			8,909			11,152			1,486			56,761
Amortization recorded to cost of sales	63			—			261			—			1,376			—			1,700
Net unrealized losses (gains) on derivatives	1,484			(4,166		)	(3,331		)	(273		)	—			—			(6,286		)
Inventory valuation adjustment	—			—			—			—			9,197			—			9,197
Lower of cost or market adjustments	14			—			—			—			400			—			414
Loss on disposal or impairment of assets, net	1,080			58			9			64			80			—			1,291
Equity-based compensation expense	—			—			—			—			23			9,443			9,466
Acquisition expense	—			—			—			7			—			560			567
Other (expense) income, net	(1,812		)	479			103			166			7			3,012			1,955
Adjusted EBITDA attributable to unconsolidated entities	2,966			(265		)	—			(111		)	3,071			—			5,661
Adjusted EBITDA attributable to noncontrolling interest	—			(339		)	—			(94		)	(12,935		)	—			(13,368		)
Other	—			(18,052		)	—			—			—			—			(18,052		)
Adjusted EBITDA	$	13,773		$	18,388		$	20,157		$	6,903		$	7,127		$	1,256		$	67,604

54

	Six Months Ended September 30, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(19,664	)	$	75,034		$	8,327	$	(11,219	)	$	161,156		$	(55,562	)	$	158,072
Depreciation and amortization	17,993			49,563			8,874		20,392			833			1,854			99,509
Amortization recorded to cost of sales	184			—			390		—			2,771			—			3,345
Net unrealized losses (gains) on derivatives	219			(834		)	3,626		209			—			—			3,220
Inventory valuation adjustment	—			—			—		—			32,693			—			32,693
Lower of cost or market adjustments	—			—			—		—			108			—			108
Loss (gain) on disposal or impairment of assets, net	9,962			(94,281		)	49		(34		)	(119,160		)	(3		)	(203,467		)
Equity-based compensation expense	—			—			—		—			—			32,994			32,994
Acquisition expense	—			—			—		2			—			1,159			1,161
Other (expense) income, net	(1,310		)	310			63		320			2,879			3,591			5,853
Adjusted EBITDA attributable to unconsolidated entities	5,074			(63		)	—		(277		)	1,676			—			6,410
Adjusted EBITDA attributable to noncontrolling interest	—			(1,631		)	—		141			—			—			(1,490		)
Other	790			—			—		—			—			—			790
Adjusted EBITDA	$	13,248		$	28,098		$	21,329	$	9,534		$	82,956		$	(15,967	)	$	139,198

	As Restated
	Six Months Ended September 30, 2015
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	11,885		$	28,704		$	19,899		$	(2,465	)	$	27,776		$	(68,711	)	$	17,088
Depreciation and amortization	20,055			43,262			7,749			17,615			25,327			2,584			116,592
Amortization recorded to cost of sales	125			—			522			—			2,754			—			3,401
Net unrealized losses (gains) on derivatives	714			(2,458		)	(740		)	(262		)	—			—			(2,746		)
Inventory valuation adjustment	—			—			—			—			19,355			—			19,355
Lower of cost or market adjustments	(1,211		)	—			—			—			(4,715		)	—			(5,926		)
Loss (gain) on disposal or impairment of assets, net	1,000			710			(191		)	113			80			—			1,712
Equity-based compensation expense	—			—			—			—			585			49,556			50,141
Acquisition expense	—			—			—			7			—			625			632
Other (expense) income, net	(5,760		)	783			207			501			383			4,666			780
Adjusted EBITDA attributable to unconsolidated entities	7,292			(259		)	—			(185		)	10,436			—			17,284
Adjusted EBITDA attributable to noncontrolling interest	—			(933		)	—			26			(29,220		)	—			(30,127		)
Other	—			(31,571		)	—			—			—			—			(31,571		)
Adjusted EBITDA	$	34,100		$	38,238		$	27,446		$	15,350		$	52,761		$	(11,280	)	$	156,615

55

Segment Operating Results for theThree Months Ended September 30, 2016 and 2015

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:

	Three Months Ended September 30,
	2016			2015			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	341,981		$	997,106		$	(655,125	)
Crude oil transportation and other	9,172			12,746			(3,574		)
Total revenues (1)	351,153			1,009,852			(658,699		)
Expenses:
Cost of sales	341,786			984,993			(643,207		)
Operating expenses	9,708			11,771			(2,063		)
General and administrative expenses	1,196			2,030			(834		)
Depreciation and amortization expense	9,025			10,053			(1,028		)
Loss on disposal or impairment of assets, net	8,477			1,080			7,397
Total expenses	370,192			1,009,927			(639,735		)
Segment operating loss	$	(19,039	)	$	(75	)	$	(18,964	)
Crude oil sold (barrels)	7,770			21,404			(13,634		)
Crude oil sold ($/barrel)	$	44.013		$	46.585		$	(2.572	)
Cost per crude oil sold ($/barrel)	$	43.988		$	46.019		$	(2.031	)
Crude oil product margin ($/barrel)	$	0.025		$	0.566		$	(0.541	)

(1) Revenues include$1.3 millionand$2.3 millionof intersegment sales during thethree months endedSeptember 30, 2016and2015, respectively, that are eliminated in our condensed consolidated statements of operations.

Crude Oil Sales.Thedecreasein revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014.Thedecreasein our sales volumes was due primarily to increased competition due to the continued crude oil production decline.In addition, we also had an increase in buy/sell transactions during thethree months endedSeptember 30, 2016, compared to thethree months endedSeptember 30, 2015. These are transactions in which we transact to purchase product from a counterparty and sell the same volumes of product to the same counterparty at a different location or time. As the revenues and costs of sales are netted for these transaction, so are the volumes.

Crude Oil Transportation and Other Revenues.Thedecreasewas due primarily to the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during thethree months endedSeptember 30, 2016, compared to thethree months endedSeptember 30, 2015, and lower revenues in our trucking and barge operations during thethree months endedSeptember 30, 2016due to a general slowdown in demand for transportation services, compared to thethree months endedSeptember 30, 2015.

Cost of Sales.Our cost of sales during thethree months endedSeptember 30, 2016wasreduced by $2.7 million of net realized gains on derivatives and increased by $1.6 million of net unrealized losses on derivatives. Our cost of sales during thethree months endedSeptember 30, 2015 was reduced by $13.4 million of net realized gains on derivatives and increased by $1.5 million of net unrealized losses on derivatives. During thethree months endedSeptember 30, 2016, our cost of sales also decreased due to the decline in crude oil prices and the decrease in volumes due to increased competition.

Operating and General and Administrative Expenses.Thedecreasewas due primarily to lower compensation expense related to a reduction in the number of employees as a result of organizational changes and lower repair and maintenance expense due to having a newer fleet of barges and the timing of repairs.

Depreciation and Amortization Expense.Thedecreasewas due primarily to certain intangible assets being fully amortized during the fiscalyear ended March 31, 2016.

56

Loss on Disposal or Impairment of Assets, Net. During the three months endedSeptember 30, 2016, we recorded a loss of $4.8 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets. During the three months endedSeptember 30, 2015, we recorded a loss of $1.1 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:

				As Restated
	Three Months Ended September 30,
	2016			2015			Change
	(in thousands, except per barrel amounts)
Revenues:
Service fees	$	28,528		$	35,203		$	(6,675	)
Recovered hydrocarbons	5,681			10,746			(5,065		)
Other revenues	5,524			1,545			3,979
Total revenues	39,733			47,494			(7,761		)
Expenses:
Cost of sales-derivative gain	(2,354		)	(8,567		)	6,213
Cost of sales-other	547			—			547
Operating expenses	20,227			30,554			(10,327		)
General and administrative expenses	625			685			(60		)
Depreciation and amortization expense	25,129			22,416			2,713
(Gain) loss on disposal or impairment of assets, net	(11		)	58			(69		)
Revaluation of liabilities	—			(15,909		)	15,909
Total expenses	44,163			29,237			14,926
Segment operating (loss) income	$	(4,430	)	$	18,257		$	(22,687	)
Water received (barrels)	46,252			54,719			(8,467		)
Service fees for water processed ($/barrel)	$	0.62		$	0.64		$	(0.02	)
Recovered hydrocarbons for water processed ($/barrel)	$	0.12		$	0.20		$	(0.08	)
Operating expenses for water processed ($/barrel)	$	0.44		$	0.56		$	(0.12	)

The following tables summarize activity separated between the following categories:

• facilities we owned before June 30, 2015, which we refer to below as “existing facilities”; and

• facilities we acquired or developed after June 30, 2015, which we refer to below as “recently acquired or developed facilities”.

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

	Three Months Ended September 30,
	2016					2015
	Service Fees		Water Barrels Processed	Fees Per  Water Barrel Processed		Service Fees		Water Barrels Processed	Fees Per  Water Barrel Processed
Existing facilities	$	23,608	35,839	$	0.66	$	34,468	53,224	$	0.65
Recently acquired or developed facilities	4,920		10,413	0.47		735		1,495	0.49
Total	$	28,528	46,252	0.62		$	35,203	54,719	0.64

57

Thedecreasein the volume processed at our existing facilities was due primarily to a slowdown in customer production as a result of the lower crude oil prices, as well as migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the new facilities.

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

	Three Months Ended September 30,
	2016					2015
	Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per  Water Barrel Processed		Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per  Water Barrel Processed
Existing facilities	$	4,563	35,839	$	0.13	$	10,684	53,224	$	0.20
Recently acquired or developed facilities	1,118		10,413	0.11		62		1,495	0.04
Total	$	5,681	46,252	0.12		$	10,746	54,719	0.20

Thedecreasein revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014 anda decreasein the amount of hydrocarbons per barrel of water processed.

Other Revenues.Other revenues include solids disposal revenues, freshwater revenues, water pipeline revenues and other revenues. Theincreasewas due primarily to an increasein revenues in the freshwater and water pipeline businesses.

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 expected to recover when processing the wastewater.Our cost of sales during thethree months endedSeptember 30, 2016included$2.2 million of net unrealized gains on derivatives and $0.2 million of net realized gains on derivatives. Our cost of sales during thethree months endedSeptember 30, 2015included $4.4 million of net realized gains on derivatives and $4.2 million of net unrealized gains on derivatives.

Cost of Sales-Other.Theincreasewas due to trucking expenses to bring wastewater to our water solutions facilities.

Operating Expenses.The following table summarizes our operating expenses (in thousands, except per barrel amounts) for the periods indicated:

						As Restated
	Three Months Ended September 30,
	2016					2015
	Operating Expenses		Water Barrels Processed	Operating Expenses Per  Water Barrel Processed		Operating Expenses		Water Barrels Processed	Operating Expenses Per  Water Barrel Processed
Existing facilities	$	17,304	35,839	$	0.48	$	30,176	53,224	$	0.57
Recently acquired or developed facilities	2,923		10,413	0.28		378		1,495	0.25
Total	$	20,227	46,252	0.44		$	30,554	54,719	0.56

Thedecreasein operating expenses for existing facilities was due primarily toloweroperating costs of water disposal wells at existing facilities due tolowervolumes processed and cost reduction efforts.

Depreciation and Amortization Expense.Of theincrease, $2.2 million related to recently acquired or developed water treatment and disposal facilities and $0.3 million related to recently developed solids processing facilities.

Revaluation of Liabilities.The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during thethree months endedSeptember 30, 2015. During thethree months endedSeptember 30, 2016, we did not identify any significant changes in our Water Solutions operations, which would require a revaluation of the contingent consideration obligation, and as such, no adjustment was recorded.

58

Liquids

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

	Three Months Ended September 30,
	2016		2015		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	101,613	$	98,770	$	2,843
Cost of sales	96,663		95,903		760
Product margin	4,950		2,867		2,083
Other product sales:
Revenues (1)	135,700		160,836		(25,136		)
Cost of sales	120,112		132,179		(12,067		)
Product margin	15,588		28,657		(13,069		)
Other revenues:
Revenues (1)	8,075		10,122		(2,047		)
Cost of sales	3,636		3,769		(133		)
Product margin	4,439		6,353		(1,914		)
Expenses:
Operating expenses	11,608		12,321		(713		)
General and administrative expenses	543		2,432		(1,889		)
Depreciation and amortization expense	4,425		2,745		1,680
Loss on disposal or impairment of assets, net	17		9		8
Total expenses	16,593		17,507		(914		)
Segment operating income	$	8,384	$	20,370	$	(11,986	)
Propane sold (gallons)	222,352		243,663		(21,311		)
Propane sold ($/gallon)	$	0.457	$	0.405	$	0.052
Cost per propane sold ($/gallon)	$	0.435	$	0.394	$	0.041
Propane product margin ($/gallon)	$	0.022	$	0.011	$	0.011
Other products sold (gallons)	188,964		232,227		(43,263		)
Other products sold ($/gallon)	$	0.718	$	0.693	$	0.025
Cost per other products sold ($/gallon)	$	0.636	$	0.569	$	0.067
Other products product margin ($/gallon)	$	0.082	$	0.124	$	(0.042	)

(1) Revenues include $11.1 million and $10.7 million of intersegment sales during the three months endedSeptember 30, 2016 and 2015, respectively, that are eliminated in our condensed consolidated statements of operations.

Propane Sales. Propane margins are higher due to selling favorable weighted cost of inventory values into a contango market. Sales volumes of propane are lower due to the lack of demand by wholesalers who entered into the current supply season with high inventory levels from the previous contract season and lack of opportunities in the spot market. We continue to be impacted by lower propane demand as a result of warmer temperatures in the prior year.

Our cost of wholesale propane sales was reduced by $0.1 million of net unrealized gains on derivatives and increased by less than $0.1 million of net realized losses on derivatives during the three months ended September 30, 2016. During the three months ended September 30, 2015, our cost of wholesale propane sales was reduced by less than $0.1 million of net unrealized gains on derivatives and increased by $0.7 million of net realized losses on derivatives. The increase in cost per gallon of propane was due to higher commodity prices.

59

Other Products Sales. The decrease in the volume of other products sold was primarily due to reductions in production volumes as a result of low crude oil prices.

Our cost of sales of other products was increased by $2.7 million of net unrealized losses on derivatives and reduced by $0.7 million of net realized gains on derivatives during the three months ended September 30, 2016. Our cost of sales of other products during the three months ended September 30, 2015 was reduced by $3.3 million of net unrealized gains on derivatives and increased by $0.2 million of net realized losses on derivatives.

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

Other Revenues. This revenue includes storage, terminaling and transportation services income. Other revenues decreased due to transportation services. While railcar costs have held steady, the value we can get for the railcar in the market has dropped significantly year over year. Our results were also negatively impacted by increased storage capacity.

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

Depreciation and Amortization Expense. Theincrease was due primarily to purchase accounting adjustments for the Sawtooth cavern acquisition during thethree months ended September 30, 2015.

60

Retail Propane

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

	Three Months Ended September 30,
	2016			2015			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues	$	36,170		$	36,119		$	51
Cost of sales	13,272			11,921			1,351
Product margin	22,898			24,198			(1,300		)
Distillate sales:
Revenues	5,589			7,678			(2,089		)
Cost of sales	4,406			5,783			(1,377		)
Product margin	1,183			1,895			(712		)
Other revenues:
Revenues	9,331			9,409			(78		)
Cost of sales	3,013			3,175			(162		)
Product margin	6,318			6,234			84
Expenses:
Operating expenses	27,132			22,421			4,711
General and administrative expenses	1,344			2,698			(1,354		)
Depreciation and amortization expense	10,705			8,909			1,796
(Gain) loss on disposal or impairment of assets, net	(65		)	64			(129		)
Total expenses	39,116			34,092			5,024
Segment operating loss	$	(8,717	)	$	(1,765	)	$	(6,952	)
Propane sold (gallons)	23,745			23,095			650
Propane sold ($/gallon)	$	1.523		$	1.564		$	(0.041	)
Cost per propane sold ($/gallon)	$	0.559		$	0.516		$	0.043
Propane product margin ($/gallon)	$	0.964		$	1.048		$	(0.084	)
Distillates sold (gallons)	2,949			3,550			(601		)
Distillates sold ($/gallon)	$	1.895		$	2.163		$	(0.268	)
Cost per distillates sold ($/gallon)	$	1.494		$	1.629		$	(0.135	)
Distillates product margin ($/gallon)	$	0.401		$	0.534		$	(0.133	)

Revenues. Propane revenues and volumes increased slightly due to acquisitions of retail propane businesses, offset by lower sales prices.

Distillates revenues and volumes decreased as the market is still suffering from the oversupply due to warmer weather in the prior winter.

Cost of Sales. The increase in propane cost is due to increasing propane commodity prices. The distillates cost was due to an increase in commodity prices.

Operating and General and Administrative Expenses. The increase was due primarily to increased compensation expense from acquisitions of retail propane businesses.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.

61

Refined Productsand Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated.As previously reported, on February 1, 2016, we sold our general partner interest in TLP.As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. Also, on April 1, 2016, we sold all of the TLP common units we owned.

	Three Months Ended September 30,
	2016			2015			Change
	(in thousands, except per barrel and per gallon amounts)
Refined products sales:
Revenues (1)	$	2,274,715		$	1,704,259		$	570,456
Cost of sales	2,265,182			1,696,664			568,518
Product margin	9,533			7,595			1,938
Renewables sales:
Revenues	95,830			93,189			2,641
Cost of sales	94,852			93,279			1,573
Product margin (loss)	978			(90		)	1,068
Service fee revenues	(121		)	28,739			(28,860		)
Expenses:
Operating expenses	4,341			25,458			(21,117		)
General and administrative expenses	1,809			4,798			(2,989		)
Depreciation and amortization expense	416			11,152			(10,736		)
(Gain) loss on disposal or impairment of assets, net	(7,563		)	80			(7,643		)
Total (income) expense, net	(997		)	41,488			(42,485		)
Segment operating income (loss)	$	11,387		$	(5,244	)	$	16,631
Refined products sold (barrels)	37,448			24,148			13,300
Refined products sold ($/barrel)	$	60.743		$	70.576		$	(9.833	)
Cost per refined products sold ($/barrel)	$	60.489		$	70.261		$	(9.772	)
Refined products product margin ($/barrel)	$	0.254		$	0.315		$	(0.061	)
Refined products product margin ($/gallon)	$	0.006		$	0.008		$	(0.002	)
Renewable products sold (barrels)	1,499			1,308			191
Renewable products sold ($/barrel)	$	63.929		$	71.245		$	(7.316	)
Cost per renewable products sold ($/barrel)	$	63.277		$	71.314		$	(8.037	)
Renewable products product margin ($/barrel)	$	0.652		$	(0.069	)	$	0.721
Renewable products product margin ($/gallon)	$	0.016		$	(0.002	)	$	0.018

(1) Revenues include$0.1 millionand$0.3 millionof intersegment sales during thethree months endedSeptember 30, 2016and2015, respectively, that are eliminated in our condensed consolidated statements of operations.

Refined Products Sales and Cost of Sales.Theincreasein revenues and cost of sales was due primarily toincreasedvolumes, partially offset by adecreasein refined products prices.Theincreasedvolumes were due primarily to an increase in pipeline capacity allocations purchased during the fiscal year ended March 31, 2016 andsix months endedSeptember 30, 2016, an expansion of our refined products operations, and the continued demand for motor fuels in the current low gasoline price environment.Product margin during thethree months endedSeptember 30, 2016was also impacted by storage fees paid to TLP which are no longer eliminated as TLP was deconsolidated on February 1, 2016.

62

Renewables Sales.Theincreasein revenues was due primarily toincreasedvolumes, partially offset by adecreasein renewables prices.Theincreasedvolumes were due primarily to being able to liquidate storage volumes as the renewables markets shifted from being in contango (a condition in which forward renewables prices are greater than spot prices) to being backwardated (a condition in which forward renewables prices are lower than spot prices) during thethree months endedSeptember 30, 2016.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses, Depreciation and Amortization Expense.The decrease in each of these line items was due primarily to the inclusion of TLP for thethree months endedSeptember 30, 2015with no comparable activity in the current period, as TLP was deconsolidated on February 1, 2016.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the three months endedSeptember 30, 2016, we recognized $7.6 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016. See Note 2 to our 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 September 30,
	2016			2015			Change
	(in thousands)
Other revenues:
Revenues	$	248		$	—		$	248
Cost of sales	113			—			113
Margin	135			—			135
Expenses:
Operating expenses	239			—			239
General and administrative expenses	22,409			11,759			10,650
Depreciation and amortization expense	903			1,486			(583		)
Gain on disposal or impairment of assets, net	(3		)	—			(3		)
Total expenses	23,548			13,245			10,303
Operating loss	$	(23,413	)	$	(13,245	)	$	(10,168	)

General and Administrative Expenses. General and administrative expenses for the three months endedSeptember 30, 2015 benefited from the reversal of incentive compensation. During the three months endedSeptember 30, 2016, we recorded additional compensation expense and increased equity based compensation due to the grant of additional service and performance awards.

Equity in Earnings of Unconsolidated Entities

Thedecreaseof$2.4 million during the three months endedSeptember 30, 2016was due primarily to a decrease of $2.5 million of earnings from TLP(including Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and Frontera Brownsville LLC (“Frontera”)) that we acquired as part of our July 2014 acquisition of TransMontaigne Inc. (“TransMontaigne”). On February 1, 2016, we deconsolidated TLP when we sold our general partner interest in TLP, and on April 1, 2016, we sold all of the TLP common units we owned.

Interest Expense

Interest expense includes interest expense on our revolving credit facilities and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations. Theincreaseof$1.9 million during the three months endedSeptember 30, 2016was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (as defined herein) (the average balance outstanding on our Revolving Credit Facility was$1.9 billionduring thethree months endedSeptember 30, 2016, compared to$1.6 billionduring thethree months endedSeptember 30, 2015), primarily to finance acquisitions and capital expenditures, partially offset by lower interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014, and we deconsolidated

63

TLP as of February 1, 2016) and lower interest expense as we repurchased a portion of the 2019 Notes (as defined herein) and 2021 Notes (as defined herein) during the three months ended March 31, 2016 and the three months ended June 30, 2016.

Gain on Early Extinguishment of Liabilities

During thethree months endedSeptember 30, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain of$0.9 millionon the release of certain contingent consideration liabilities.

Other Income, Net

The following table summarizes the components ofother income, netfor the periods indicated:

	Three Months Ended September 30,
	2016			2015
	(in thousands)
Interest income (1)	$	1,997		$	2,823
Crude oil marketing arrangement (2)	(30		)	(1,887		)
Other	114			1,019
Other income, net	$	2,081		$	1,955

(1) Relates primarily toa loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third partyand to loan receivables from equity method investees.On June 3, 2016, we acquired the remaining65%ownership interest inan equity method investee 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 generated from a joint crude oil marketing arrangement.

Income Tax Expense (Benefit)

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. Our fiscal years 2013 to 2016 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

Income tax expense was $0.5 million during the three months endedSeptember 30, 2016, compared to an income tax benefit of $2.8 million during the three months endedSeptember 30, 2015. Income tax benefit during thethree months endedSeptember 30, 2015included a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

Noncontrolling Interests

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

Thedecreaseof$3.6 million during the three months endedSeptember 30, 2016was due primarily to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our general partner interest in TLP.

64

Segment Operating Results for theSix Months Ended September 30, 2016 and 2015

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:

	Six Months Ended September 30,
	2016			2015		Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	756,600		$	2,309,889	$	(1,553,289	)
Crude oil transportation and other	22,106			31,695		(9,589		)
Total revenues (1)	778,706			2,341,584		(1,562,878		)
Expenses:
Cost of sales	748,618			2,280,933		(1,532,315		)
Operating expenses	18,822			23,601		(4,779		)
General and administrative expenses	2,975			4,110		(1,135		)
Depreciation and amortization expense	17,993			20,055		(2,062		)
Loss on disposal or impairment of assets, net	9,962			1,000		8,962
Total expenses	798,370			2,329,699		(1,531,329		)
Segment operating (loss) income	$	(19,664	)	$	11,885	$	(31,549	)
Crude oil sold (barrels)	17,311			45,087		(27,776		)
Crude oil sold ($/barrel)	$	43.706		$	51.232	$	(7.526	)
Cost per crude oil sold ($/barrel)	$	43.245		$	50.590	$	(7.345	)
Crude oil product margin ($/barrel)	$	0.461		$	0.642	$	(0.181	)

(1) Revenues include$2.9 millionand$6.2 millionof intersegment sales during thesix months endedSeptember 30, 2016and2015, respectively, that are eliminated in our condensed consolidated statements of operations.

Crude Oil Sales.Thedecreasein revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014.Thedecreasein our sales volumes was due primarily to increased competition due to the continued crude oil production decline.In addition, we also had an increase in buy/sell transactions during thesix months endedSeptember 30, 2016, compared to thesix months endedSeptember 30, 2015. These are transactions in which we transact to purchase product from a counterparty and sell the same volumes of product to the same counterparty at a different location or time. As the revenues and costs of sales are netted for these transaction, so are the volumes.

Crude Oil Transportation and Other Revenues.Thedecreasewas due primarily to the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during thesix months endedSeptember 30, 2016, compared to thesix months endedSeptember 30, 2015, and lower revenues in our trucking and barge operations during thesix months endedSeptember 30, 2016due to a general slowdown in demand for transportation services, compared to thesix months endedSeptember 30, 2015.

Cost of Sales.Our cost of sales during thesix months endedSeptember 30, 2016wasincreased by $5.5 million of net realized losses on derivatives and $0.2 million of net unrealized losses on derivatives. Our cost of sales during thesix months endedSeptember 30, 2015 was reduced by $2.1 million of net realized gains on derivatives and increased by $0.7 million of net unrealized losses on derivatives. During thesix months endedSeptember 30, 2016, our cost of sales also decreased due to the decline in crude oil prices and the decrease in volumes due to increased competition.

Operating and General and Administrative Expenses.Thedecreasewas due primarily to lower compensation expense related to a reduction in the number of employees as a result of organizational changes and lower repair and maintenance expense due to having a newer fleet of barges and the timing of repairs.

Depreciation and Amortization Expense.Thedecreasewas due primarily to certain intangible assets being fully amortized during the fiscalyear ended March 31, 2016.

65

Loss on Disposal or Impairment of Assets, Net. During the six months endedSeptember 30, 2016, we recorded a loss of $6.3 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets. During the six months endedSeptember 30, 2015, we recorded a loss of $1.0 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:

				As Restated
	Six Months Ended September 30,
	2016			2015			Change
	(in thousands, except per barrel amounts)
Revenues:
Service fees	$	54,225		$	71,941		$	(17,716	)
Recovered hydrocarbons	12,877			26,564			(13,687		)
Other revenues	8,384			3,282			5,102
Total revenues	75,486			101,787			(26,301		)
Expenses:
Cost of sales-derivative loss (gain)	2,687			(4,960		)	7,647
Cost of sales-other	707			—			707
Operating expenses	40,505			59,772			(19,267		)
General and administrative expenses	1,271			1,403			(132		)
Depreciation and amortization expense	49,563			43,262			6,301
(Gain) loss on disposal or impairment of assets, net	(94,281		)	710			(94,991		)
Revaluation of liabilities	—			(27,104		)	27,104
Total expenses	452			73,083			(72,631		)
Segment operating income	$	75,034		$	28,704		$	46,330
Water received (barrels)	87,424			109,195			(21,771		)
Service fees for water processed ($/barrel)	$	0.62		$	0.66		$	(0.04	)
Recovered hydrocarbons for water processed ($/barrel)	$	0.15		$	0.24		$	(0.09	)
Operating expenses for water processed ($/barrel)	$	0.46		$	0.55		$	(0.09	)

The following tables summarize activity separated between the following categories:

• facilities we owned before March 31, 2015, which we refer to below as “existing facilities”; and

• facilities we acquired or developed after March 31, 2015, which we refer to below as “recently acquired or developed facilities”.

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

	Six Months Ended September 30,
	2016					2015
	Service Fees		Water Barrels Processed	Fees Per  Water Barrel Processed		Service Fees		Water Barrels Processed	Fees Per  Water Barrel Processed
Existing facilities	$	39,103	58,302	$	0.67	$	63,486	95,713	$	0.66
Recently acquired or developed facilities	15,122		29,122	0.52		8,455		13,482	0.63
Total	$	54,225	87,424	0.62		$	71,941	109,195	0.66

66

Thedecreasein the volume processed at our existing facilities was due primarily to a slowdown in customer production as a result of the lower crude oil prices, as well as migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the new facilities.

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

	Six Months Ended September 30,
	2016					2015
	Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per  Water Barrel Processed		Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per  Water Barrel Processed
Existing facilities	$	9,417	58,302	$	0.16	$	24,718	95,713	$	0.26
Recently acquired or developed facilities	3,460		29,122	0.12		1,846		13,482	0.14
Total	$	12,877	87,424	0.15		$	26,564	109,195	0.24

Thedecreasein revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014 anda decreasein the amount of hydrocarbons per barrel of water processed.

Other Revenues.Theincreasewas due primarily to an increasein revenues in the freshwater and water pipeline businesses.

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 expected to recover when processing the wastewater.Our cost of sales during thesix months endedSeptember 30, 2016included$3.5 million of net realized losses on derivatives and $0.8 million of net unrealized gains on derivatives. Our cost of sales during thesix months endedSeptember 30, 2015included $2.5 million of net realized gains on derivatives and $2.5 million of net unrealized gains on derivatives.

Cost of Sales-Other.Theincreasewas due to trucking expenses to bring wastewater to our water solutions facilities.

Operating Expenses.The following table summarizes our operating expenses (in thousands, except per barrel amounts) for the periods indicated:

						As Restated
	Six Months Ended September 30,
	2016					2015
	Operating Expenses		Water Barrels Processed	Operating Expenses Per  Water Barrel Processed		Operating Expenses		Water Barrels Processed	Operating Expenses Per  Water Barrel Processed
Existing facilities	$	30,608	58,302	$	0.52	$	54,491	95,713	$	0.57
Recently acquired or developed facilities	9,897		29,122	0.34		5,281		13,482	0.39
Total	$	40,505	87,424	0.46		$	59,772	109,195	0.55

Thedecreasein operating expenses for existing facilities was due primarily toloweroperating costs of water disposal wells at existing facilities due tolowervolumes processed and cost reduction efforts.

Depreciation and Amortization Expense.Of theincrease, $5.2 million related to recently acquired or developed water treatment and disposal facilities and $1.3 million related to recently developed solids processing facilities.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the six months endedSeptember 30, 2016, we recorded the reversal of $124.7 million of the previously recorded $380.2 million goodwill impairment charge recorded during the three months ended March 31, 2016 (see Note 6 to our condensed consolidated financial statements included in this Quarterly Report). During thesix months endedSeptember 30, 2016, we wrote-off$5.2 millionrelated to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis (see Note 7 to our condensed consolidated financial statements included in this Quarterly Report). During the six months endedSeptember 30, 2016, we recorded a loss of $22.7 million related to the termination of the development agreement, which included the carrying value of the development agreement asset that was written off (seeNote 15 to our condensed consolidated financial statements included

67

in this Quarterly Report). During thesix months endedSeptember 30, 2016, we recorded an impairment of$1.7 millionrelated to a loan receivable from an equity method investee. During the six months endedSeptember 30, 2016, we recorded a loss of $0.8 million on the sales of certain assets. During the six months endedSeptember 30, 2015, we recorded a loss of $0.7 million on the sales of certain assets.

Revaluation of Liabilities.The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during thesix months endedSeptember 30, 2015. During thesix months endedSeptember 30, 2016, we did not identify any significant changes in our Water Solutions operations, which would require a revaluation of the contingent consideration obligation, and as such, no adjustment was recorded.

Liquids

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

	Six Months Ended September 30,
	2016		2015			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	198,084	$	204,260		$	(6,176	)
Cost of sales	187,826		205,273			(17,447		)
Product margin (loss)	10,258		(1,013		)	11,271
Other product sales:
Revenues (1)	249,435		308,347			(58,912		)
Cost of sales	230,222		265,347			(35,125		)
Product margin	19,213		43,000			(23,787		)
Other revenues:
Revenues (1)	15,222		19,622			(4,400		)
Cost of sales	5,659		7,023			(1,364		)
Product margin	9,563		12,599			(3,036		)
Expenses:
Operating expenses	19,540		22,492			(2,952		)
General and administrative expenses	2,244		4,637			(2,393		)
Depreciation and amortization expense	8,874		7,749			1,125
Loss (gain) on disposal or impairment of assets, net	49		(191		)	240
Total expenses	30,707		34,687			(3,980		)
Segment operating income	$	8,327	$	19,899		$	(11,572	)
Propane sold (gallons)	426,636		471,615			(44,979		)
Propane sold ($/gallon)	$	0.464	$	0.433		$	0.031
Cost per propane sold ($/gallon)	$	0.440	$	0.435		$	0.005
Propane product margin ($/gallon)	$	0.024	$	(0.002	)	$	0.026
Other products sold (gallons)	364,932		424,214			(59,282		)
Other products sold ($/gallon)	$	0.684	$	0.727		$	(0.043	)
Cost per other products sold ($/gallon)	$	0.631	$	0.626		$	0.005
Other products product margin ($/gallon)	$	0.053	$	0.101		$	(0.048	)

(1) Revenues include $23.4 million and $24.3 million of intersegment sales during the six months endedSeptember 30, 2016 and 2015, respectively, that are eliminated in our condensed consolidated statements of operations.

68

Propane Sales. The decrease in volumes was due to significantly warmer temperatures in the prior year winter for which suppliers had full storage capacity and their ordering has been slow to pick up and also due to lack of opportunity in the spot market.

Our cost of wholesale propane sales was reduced by $1.0 million of net unrealized gains on derivatives and $0.5 million of net realized gains on derivatives during six months ended September 30, 2016. During the six months ended September 30, 2015, our cost of wholesale propane sales was increased by $0.9 million of net unrealized losses on derivatives and reduced by $0.1 million of net realized gains on derivatives. The cost of propane remained relatively flat as there was an insignificant increase in commodity prices year over year. The reduction in cost of sales is due primarily to the decrease in volumes.

Product margins per gallon of propane sold were higher during the six months ended September 30, 2016 than during the six months ended September 30, 2015. Product margins have improved because depressed market prices through last winter have led to lower inventory values to start out the new supply year. Propane prices declined during the six months ended September 30, 2015, which had an adverse impact on product margins.

Other Products Sales. The decrease in the volume of other products sold was primarily due to reductions in production volumes as a result of low crude oil prices.

Our cost of sales of other products was increased by $4.7 million of net unrealized losses on derivatives and reduced by $1.2 million of net realized gains on derivatives during the six months ended September 30, 2016. Our cost of sales of other products during the six months ended September 30, 2015 was reduced by $1.6 million of net unrealized gains on derivatives and increased by $0.6 million of net realized losses on derivatives.

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

Other Revenues. This revenue includes storage, terminaling and transportation services income. Other revenues decreased due to transportation services and increased storage capacity. While railcar costs have held steady, the value we are able to realize for the railcar in the market has dropped significantly year over year.

Operating and General and Administrative Expenses. The decrease was due primarily to a reduction in overall compensation expense due to lower incentive compensation as well as continued cost management monitoring which focuses on reductions of expenses.

Depreciation and Amortization Expense. The increase was due primarily to purchase accounting adjustments for the Sawtooth cavern acquisition during the three months ended September 30, 2015.

69

Retail Propane

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

	Six Months Ended September 30,
	2016			2015			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	77,811		$	79,304		$	(1,493	)
Cost of sales	28,101			28,232			(131		)
Product margin	49,710			51,072			(1,362		)
Distillate sales:
Revenues (1)	16,044			20,625			(4,581		)
Cost of sales	11,944			15,975			(4,031		)
Product margin	4,100			4,650			(550		)
Other revenues:
Revenues	17,638			17,724			(86		)
Cost of sales	5,466			6,236			(770		)
Product margin	12,172			11,488			684
Expenses:
Operating expenses	52,349			46,143			6,206
General and administrative expenses	4,494			5,804			(1,310		)
Depreciation and amortization expense	20,392			17,615			2,777
(Gain) loss on disposal or impairment of assets, net	(34		)	113			(147		)
Total expenses	77,201			69,675			7,526
Segment operating loss	$	(11,219	)	$	(2,465	)	$	(8,754	)
Propane sold (gallons)	49,361			47,502			1,859
Propane sold ($/gallon)	$	1.576		$	1.669		$	(0.093	)
Cost per propane sold ($/gallon)	$	0.569		$	0.594		$	(0.025	)
Propane product margin ($/gallon)	$	1.007		$	1.075		$	(0.068	)
Distillates sold (gallons)	8,366			8,643			(277		)
Distillates sold ($/gallon)	$	1.918		$	2.386		$	(0.468	)
Cost per distillates sold ($/gallon)	$	1.428		$	1.848		$	(0.420	)
Distillates product margin ($/gallon)	$	0.490		$	0.538		$	(0.048	)

(1) Revenues include less than $0.1 million of intersegment sales during the six months endedSeptember 30, 2016 that are eliminated in our condensed consolidated statement of operations.

Revenues. The decrease in both propane and distillate revenues was due to lower prices per gallon due to an oversupply in the propane market, which lowered commodity prices, as well as the significantly warmer temperatures during the winter in the prior year. Propane volumes increased slightly due to acquisitions of retail propane businesses.

Cost of Sales. The decrease for both propane and distillates was due to lower commodity prices.

Operating and General and Administrative Expenses. The increase was due primarily to increased compensation expense from acquisitions of retail propane businesses.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.

70

Refined Productsand Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated.As previously reported, on February 1, 2016, we sold our general partner interest in TLP.As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. Also, on April 1, 2016, we sold all of the TLP common units we owned.

	Six Months Ended September 30,
	2016			2015		Change
	(in thousands, except per barrel and per gallon amounts)
Refined products sales:
Revenues (1)	$	4,151,572		$	3,413,208	$	738,364
Cost of sales	4,099,509			3,356,161		743,348
Product margin	52,063			57,047		(4,984		)
Renewables sales:
Revenues	202,312			199,342		2,970
Cost of sales	200,654			199,095		1,559
Product margin	1,658			247		1,411
Service fee revenues	11,145			56,812		(45,667		)
Expenses:
Operating expenses	16,663			51,321		(34,658		)
General and administrative expenses	5,374			9,602		(4,228		)
Depreciation and amortization expense	833			25,327		(24,494		)
(Gain) loss on disposal or impairment of assets, net	(119,160		)	80		(119,240		)
Total (income) expense, net	(96,290		)	86,330		(182,620		)
Segment operating income	$	161,156		$	27,776	$	133,380
Refined products sold (barrels)	68,251			45,075		23,176
Refined products sold ($/barrel)	$	60.828		$	75.723	$	(14.895	)
Cost per refined products sold ($/barrel)	$	60.065		$	74.457	$	(14.392	)
Refined products product margin ($/barrel)	$	0.763		$	1.266	$	(0.503	)
Refined products product margin ($/gallon)	$	0.018		$	0.030	$	(0.012	)
Renewable products sold (barrels)	3,280			2,683		597
Renewable products sold ($/barrel)	$	61.680		$	74.298	$	(12.618	)
Cost per renewable products sold ($/barrel)	$	61.175		$	74.206	$	(13.031	)
Renewable products product margin ($/barrel)	$	0.505		$	0.092	$	0.413
Renewable products product margin ($/gallon)	$	0.012		$	0.002	$	0.010

(1) Revenues include$0.1 millionand$0.5 millionof intersegment sales during thesix months endedSeptember 30, 2016and2015, respectively, that are eliminated in our condensed consolidated statements of operations.

Refined Products Sales and Cost of Sales.Theincreasein revenues and cost of sales was due primarily toincreasedvolumes, partially offset by adecreasein refined products prices.Theincreasedvolumes were due primarily to an increase in pipeline capacity allocations purchased during the fiscal year ended March 31, 2016 andsix months endedSeptember 30, 2016, an expansion of our refined products operations, and the continued demand for motor fuels in the current low gasoline price environment.Product margin during thesix months endedSeptember 30, 2016was also impacted by storage fees paid to TLP which are no longer eliminated as TLP was deconsolidated on February 1, 2016.

71

Renewables Sales.Theincreasein revenues was due primarily toincreasedvolumes, partially offset by adecreasein renewables prices.Theincreasedvolumes were due primarily to being able to liquidate storage volumes as the renewables markets shifted from being in contango (a condition in which forward renewables prices are greater than spot prices) to being backwardated (a condition in which forward renewables prices are lower than spot prices) during thesix months endedSeptember 30, 2016.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses, Depreciation and Amortization Expense.The decrease in each of these line items was due primarily to the inclusion of TLP for thesix months endedSeptember 30, 2015with no comparable activity in the current period, as TLP was deconsolidated on February 1, 2016.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the six months endedSeptember 30, 2016, we recognized a $104.1 million gain from the sale of all of the TLP units we owned. During the six months endedSeptember 30, 2016, we recognized $15.1 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016. See Note 2 to our 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:

	Six Months Ended September 30,
	2016			2015			Change
	(in thousands)
Other revenues:
Revenues	$	515		$	—		$	515
Cost of sales	223			—			223
Margin	292			—			292
Expenses:
Operating expenses	564			—			564
General and administrative expenses	53,439			66,127			(12,688		)
Depreciation and amortization expense	1,854			2,584			(730		)
Gain on disposal or impairment of assets, net	(3		)	—			(3		)
Total expenses	55,854			68,711			(12,857		)
Operating loss	$	(55,562	)	$	(68,711	)	$	13,149

General and Administrative Expenses. The decrease was due primarily to lower equity based compensation expense. For our performance units, we recorded expense of $3.1 million during the six months ended September 30, 2016, compared to $18.1 million during the six months ended September 30, 2015. The six months ended September 30, 2015 included the initial grant and vesting of the first tranche of the performance units. The expense associated with the service award units (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $27.7 million during the six months ended September 30, 2016, compared to $23.4 million during the six months ended September 30, 2015. The increase was due primarily to the grant of additional awards. See Note 11 to our condensed consolidated financial statements included in this Quarterly Report for a further discussion of our equity based compensation awards.

Equity in Earnings of Unconsolidated Entities

Thedecreaseof$10.7 million during the six months endedSeptember 30, 2016was due primarily to a decrease of $8.3 million of earnings from TLP(includingBOSTCOandFrontera) that we acquired as part of our July 2014 acquisition of TransMontaigne. On February 1, 2016, we deconsolidated TLP when we sold our general partner interest in TLP, and on April 1, 2016, we sold all of the TLP common units we owned. Also contributing to this decrease was a decrease of $2.3 million in earnings from our investments in Glass Mountain Pipeline, LLC.

Revaluation of Investments

On June 3, 2016, we acquired the remaining65%ownership interest in a water supply company. Prior to the completion of this transaction, we accounted for our previously held35% ownership interest of this water supply company

72

using the equity method of accounting (see Note 2 to our condensed consolidated financial statements included in this Quarterly Report). As we now own a controlling interest in this entity, we revalued our previously held35%ownership interest to fair valueand 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 gain on bargain purchase of$0.6 million.

Interest Expense

Theincreaseof$1.5 million during the six months endedSeptember 30, 2016was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (as defined herein) (the average balance outstanding on our Revolving Credit Facility was$1.9 billionduring thesix months endedSeptember 30, 2016, compared to$1.6 billionduring thesix months endedSeptember 30, 2015), primarily to finance acquisitions and capital expenditures, partially offset by lower interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014, and we deconsolidated TLP as of February 1, 2016) and lower interest expense as we repurchased a portion of the 2019 Notes (as defined herein) and 2021 Notes (as defined herein) during the three months ended March 31, 2016 and the three months ended June 30, 2016.

Gain on Early Extinguishment of Liabilities

During the six months endedSeptember 30, 2016, we repurchased $5.0 million of our 2019 Notes (as defined herein) and $19.2 million of our 2021 Notes (as defined herein) for an aggregate purchase price of $15.1 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of these notes of $8.6 million (net of the write off of debt issuance costs of $0.5 million).

As discussed in Note 15 to our condensed consolidated financial statements included in this Quarterly Report, we accounted for the termination of the development agreement as an acquisition of assets (see Note 7 to our condensed consolidated financial statements included in this Quarterly Report for a further discussion) and recorded a gain of $21.3 million on the release of $46.8 million of contingent consideration liabilities.

During thesix months endedSeptember 30, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain of$0.9 millionon the release of certain contingent consideration liabilities.

Other Income, Net

The following table summarizes the components ofother income, netfor the periods indicated:

	Six Months Ended September 30,
	2016			2015
	(in thousands)
Interest income (1)	$	4,420		$	6,700
Crude oil marketing arrangement (2)	(1,551		)	(5,835		)
Other (3)	2,984			(85		)
Other income, net	$	5,853		$	780

(1) Relates primarily toa loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third partyand to loan receivables from equity method investees.On June 3, 2016, we acquired the remaining65%ownership interest inan equity method investee 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 generated from a joint crude oil marketing arrangement.

(3) During the six months endedSeptember 30, 2016, we received a distribution from TLP of $2.9 million pursuant to the agreement to sell all of the TLP common units we owned in April 2016.

Income Tax Expense (Benefit)

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.

73

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2013 to 2016 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

Income tax expense was $0.9 million during the six months endedSeptember 30, 2016, compared to an income tax benefit of $2.2 million during the six months endedSeptember 30, 2015. Income tax benefit during thesix months endedSeptember 30, 2015included a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

Noncontrolling Interests

Thedecreaseof$2.1 million during the six months endedSeptember 30, 2016was due primarily to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our general partner interest in TLP, partially offset by adjustments related to noncontrolling interests.

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. See Note 8 to our 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 business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our Retail Propane and Liquids segments are the greatest.

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

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital 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.

We have historically pursued a strategy of growth through acquisitions. Under current market conditions, the cost of capital is much higher than it has been in recent years; prospective lenders seek much higher interest rates than they have sought in the past, and at our prior distribution level of $0.64 per common unit, the yield on our common units was much higher than it had been in the past. In April 2016, the board of directors of our general partner decided to reduce our distribution level from $0.64 per common unit to $0.39 per common unit. At that time, we expected the reduction in the distribution to provide us with approximately $170 million of annual cash savings to enhance liquidity, repay indebtedness and/or invest in selected growth projects.

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 our assets that will be connected to the Grand Mesa Pipeline and the continued development of Sawtooth natural gas liquids storage caverns, among others. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility, asset sales or other forms of financing.

74

Other sources of liquidity during the six months endedSeptember 30, 2016 are discussed below.

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned toArcLight Capital Partners for approximately$112.4 millionin cash and recorded a gain on disposal of$104.1 millionduring thesix months endedSeptember 30, 2016.

Class A Convertible Preferred Units

During the six months endedSeptember 30, 2016, we issued $240 million of 10.75% Class A Convertible Preferred Units to Oaktree Capital Management L.P. and its co-investors. See Note 11 to our condensed consolidated financial statements included in this Quarterly Report which discusses the preferences, rights, powers and duties of holders of the Preferred Units.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with an ATM Program pursuant to which we may issue and sell common units for up to$200.0 millionin gross proceeds. We are under no obligation to issue equity under the ATM Program. We intend to use the net proceeds from any sales under the ATM Program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. During thethree months endedSeptember 30, 2016, we sold524,000common units for proceeds of$9.6 million, net of offering costs ofless than $0.1 million. In connection with the issuance of the common units, we issued524general partner units to our general partner andless than $0.1 millionin order to maintain its0.1%general partner interest in us.

Subsequent to September 30, 2016, we sold an additional192,000common units for proceeds of$3.7 million, net of offering costs ofless than $0.1 million.

Long-Term Debt

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at September 30, 2016. At that date, we had outstanding borrowings of$1.312 billionon the Expansion Capital Facility.The Working Capital Facility had a total capacity of$1.038 billionfor cash borrowings and letters of credit atSeptember 30, 2016. At that date, we had outstanding borrowings of$710.5 millionand outstanding letters of credit of $75.3 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50%to1.75%per year or (ii) an adjusted LIBOR rate plus a margin of1.50%to2.75% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At September 30, 2016, the borrowings under the Credit Agreement had an average interest rateof2.83%, calculated as the LIBOR rate of0.53%plus a margin of2.25%for LIBOR borrowings and the prime rate of3.50%plus a margin of1.25%on alternate base rate borrowings.AtSeptember 30, 2016, the interest rate in effect on letters of credit was2.25%. Commitment fees are charged at a rate ranging from0.38%to0.50% on any unused capacity.

75

The Revolving Credit Facility is secured by substantially all of our assets. The Credit Agreement also specifies that our leverage ratio cannot be more than4.75to1 and that our interest coverage ratio cannot be less than2.75to1at any quarter end.AtSeptember 30, 2016, our leverage ratio was approximately4.15to1and our interest coverage ratio was approximately4.60to1.

At September 30, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued$400.0 millionof5.125% Senior Notes Due 2019 (the “2019 Notes”). During thethree months ended June 30, 2016, we repurchased$5.0 millionof our 2019 Notes for an aggregate purchase price of$3.1 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of$1.8 million(net of the write off of debt issuance costs of$0.1 million).

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued$450.0 millionof6.875%Senior Notes Due 2021 (the “2021 Notes”). During thethree months endedJune 30, 2016,we repurchased$19.2 millionof our 2021 Notes for an aggregate purchase price of$12.0 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of$6.8 million(net of the write off of debt issuance costs of$0.4 million).

The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued$250.0 millionof Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of$25.0 millionbeginning on December 19, 2017 and ending on the maturity date of June 19, 2022.We have the option to prepay outstanding principal, although we would incur a prepayment penalty.On September 30, 2016, we amended our Note Purchase Agreement which, among other things, changes the maximum allowable leverage ratio to match the maximum allowable leverage ratio and the calculation of such ratio under our Credit Agreement. Additionally, the amendment provides for an increase in interest charged should our leverage ratio exceed certain predetermined levels. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

AtSeptember 30, 2016, we were in compliance with the covenants under the Note Purchase Agreement.

2023 Notes

As described in Note 16, we issued $700.0 million of senior unsecured notes during October 2016. These senior unsecured notes bear interest at a fixed rate of 7.50% and mature on November 1, 2023.

76

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)
Six Months Ended September 30, 2016
Expansion capital borrowings	$	1,258,478	$	1,153,500	$	1,338,000
Working capital borrowings	629,292		465,500		718,000
Six Months Ended September 30, 2015
Expansion capital borrowings	$	893,002	$	739,500	$	1,083,000
Working capital borrowings	672,921		582,500		756,000
TLP credit facility borrowings	253,247		245,000		263,400

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 (1)		Maintenance (2)		Total
	(in thousands)
Three Months Ended September 30,
2016	$	48,781	$	6,401	$	55,182
2015	87,419		15,452		102,871
Six Months Ended September 30,
2016	$	143,884	$	12,696	$	156,580
2015	200,532		26,006		226,538

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

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

Cash Flows

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

	Six Months Ended September 30,
Cash Flows Provided by (Used in)	2016			2015
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	81,184		$	78,481
Changes in operating assets and liabilities	(137,583		)	95,614
Operating activities	$	(56,399	)	$	174,095
Investing activities	(235,542		)	(340,930		)
Financing activities	287,192			155,585

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

77

requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories.

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

Investing Activities. Net cash used in investing activities was $235.5 million during the six months endedSeptember 30, 2016, compared to $340.9 million during the six months endedSeptember 30, 2015. The decrease in net cash used in investing activities was due primarily to:

• $112.4 million in proceeds received from the sale of the TLP common units we owned during the six months endedSeptember 30, 2016;

• a decrease in capital expenditures from $222.3 million during the six months endedSeptember 30, 2015 to $159.7 million during the six months endedSeptember 30, 2016;

• a $37.2 milliondecrease in cash paid for acquisitions during the six months endedSeptember 30, 2016; and

• a $13.9 milliondecrease related to a loan receivable from an equity method investee as we purchased the remaining ownership interest in this equity method investee and, therefore, consolidated this previous equity method investee in our condensed consolidated financial statements during the six months endedSeptember 30, 2016.

These decreases were partially offset by:

• a $68.0 millionincrease in cash flows from derivatives;

• $42.0 millionto acquire certain refined product pipeline capacity allocations from other shippers on the Colonial pipeline during the six months endedSeptember 30, 2016; and

• a $16.9 million payment to terminate the development agreement (see Note 15 to our condensed consolidated financial statements included in this Quarterly Report).

Financing Activities. Net cash provided by financing activities was $287.2 million during the six months endedSeptember 30, 2016, compared to $155.6 million during the six months endedSeptember 30, 2015. The increase in net cash provided by financing activities was due primarily to:

• $235.0 million in proceeds received (net of offering costs) from the sale of our Preferred Units and warrants during the six months endedSeptember 30, 2016; and

• a decrease of $86.1 million in distributions paid to our partners and noncontrolling interest owners during the six months endedSeptember 30, 2016.

These increases were partially offset by:

• a $173.6 milliondecrease in borrowings on our revolving credit facilities (net of repayments) to fund our operating or investing requirements during the six months endedSeptember 30, 2016;

• a $25.9 million release of contingent consideration liabilities related to the termination of the development agreement during the six months endedSeptember 30, 2016 (see Note 15 to our condensed consolidated financial statements included in this Quarterly Report); and

• $15.1 million in repurchases of a portion of our outstanding senior notes during the six months endedSeptember 30, 2016.

78

The following table summarizes common unit distributions declared during our current and prior fiscal years:

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, 2015	May 5, 2015	May 15, 2015	$	0.6250	$	59,651	$	13,446
July 23, 2015	August 3, 2015	August 14, 2015	0.6325		66,248		15,483
October 22, 2015	November 3, 2015	November 13, 2015	0.6400		67,313		16,277
January 21, 2016	February 3, 2016	February 15, 2016	0.6400		67,310		16,279
April 21, 2016	May 3, 2016	May 13, 2016	0.3900		40,626		70
July 22, 2016	August 4, 2016	August 12, 2016	0.3900		41,146		71
October 20, 2016	November 4, 2016	November 14, 2016	0.3900		41,907		72

Distributions on the Partnership’s outstanding Class A Convertible Preferred Units are declared and paid quarterly. On July 22, 2016, $1.8 million of distributions were declared and paid to the holders of the Preferred Units on August 12, 2016. On October 20, 2016, we declared a distribution of $6.4 million to be paid to the holders of the Preferred Units on November 14, 2016.

Contractual Obligations

The following table summarizes our contractual obligations at September 30, 2016 for our fiscal years ending thereafter:

			Six Months Ending March 31,		Year Ending March 31,
	Total		2017		2018		2019		2020		2021		Thereafter
	(in thousands)
Principal payments on long-term debt:
Expansion capital borrowings	$	1,312,000	$	—	$	—	$	1,312,000	$	—	$	—	$	—
Working capital borrowings	710,500		—		—		710,500		—		—		—
2019 Notes	383,467		—		—		—		383,467		—		—
2021 Notes	369,063		—		—		—		—		—		369,063
2022 Notes	250,000		—		25,000		50,000		50,000		50,000		75,000
Other long-term debt	59,506		3,405		8,014		6,857		6,372		34,728		130
Interest payments on long-term debt:
Revolving Credit Facility (1)	128,977		30,643		61,459		36,875		—		—		—
2019 Notes	58,958		9,826		19,653		19,653		9,826		—		—
2021 Notes	139,552		12,687		25,373		25,373		25,373		25,373		25,373
2022 Notes	58,188		8,313		16,209		13,300		9,975		6,650		3,741
Other long-term debt	12,690		1,911		3,460		2,994		2,553		1,764		8
Letters of credit	75,274		—		—		75,274		—		—		—
Future minimum lease payments under noncancelable operating leases	597,874		67,837		122,935		101,047		90,112		80,457		135,486
Future minimum throughput payments under noncancelable agreements (2)	172,678		26,008		52,082		52,170		42,418		—		—
Construction commitments (3)	18,300		18,300		—		—		—		—		—
Fixed-price commodity purchase commitments (4)	106,789		105,779		1,010		—		—		—		—
Index-price commodity purchase commitments (5)	1,002,293		735,847		126,812		88,675		50,959		—		—
Total contractual obligations	$	5,456,109	$	1,020,556	$	462,007	$	2,494,718	$	671,055	$	198,972	$	608,801

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 2016. See Note 8 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

79

(2) We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity.

(3) At September 30, 2016, we had the following construction commitments:

• As part of the Grand Mesa Pipeline project, we will have some assets connected to the pipeline. At September 30, 2016, the remaining costs for these assets are approximately $15.2 million. We expect these assets to be completed during the third quarter of fiscal year 2017.

• In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. At September 30, 2016, the remaining costs for this project are $3.1 million. We expect this project to be completed by the end of the third quarter of fiscal year 2017.

(4)    At September 30, 2016, we had the following fixed-price purchase commitments (in thousands):

	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
2017 (six months)	$	88,079	1,993	$	17,700	33,324
2018	—		—	1,010		2,268
Total	$	88,079	1,993	$	18,710	35,592

(5)    At September 30, 2016, we had the following index-price purchase commitments (in thousands):

	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
2017 (six months)	$	393,834	8,781	$	342,013	578,312
2018	121,805		2,790	5,007		8,732
2019	88,675		1,825	—		—
2020	50,959		1,070	—		—
Total	$	655,273	14,466	$	347,020	587,044

Index prices are based on a forward price curve at September 30, 2016. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2016 would result in a change of $58.7 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2016 would result in a change of $14.5 million in the value of our index-price crude oil purchase commitments.

Sales Contracts

We have entered into product sales contracts for which we expect the parties to physically settle the inventory in future periods. At September 30, 2016, we had the following sales contract volumes (in thousands):

Natural gas liquids fixed-price (gallons)	163,546
Natural gas liquids index-price (gallons)	414,042
Crude oil fixed-price (barrels)	3,415
Crude oil index-price (barrels)	12,953

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases discussed in Note 10 to our condensed consolidated financial statements included in this Quarterly Report.

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.

80

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our 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 the Partnership’s 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.

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.AtSeptember 30, 2016, we had$2.0 billionof outstanding borrowings under our Revolving Credit Facility at an average interest rate of2.83%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.5 million, based on borrowings outstanding at September 30, 2016.

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 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.AtSeptember 30, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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

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

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales. The following table summarizes the hypothetical impact on the

81

September 30, 2016 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)	$	(2,171	)
Crude oil (Water Solutions segment)	(631		)
Propane (Liquids segment)	1,038
Other products (Liquids segment)	(3,365		)
Refined products (Refined Products and Renewables segment)	(36,090		)
Renewables (Refined Products and Renewables segment)	(1,344		)
Canadian dollars (Liquids segment)	859

Fair Value

We use observable market values for determining the fair value of our derivative instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 4.Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13(a)-15(e) and 15(d)-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the Securities and Exchange Commission and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure.

We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at September 30, 2016. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of September 30, 2016, such disclosure controls and procedures were effective to provide the reasonable assurance discussed 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 endedSeptember 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

82

PART II

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 10 to our condensed consolidated financial statements in Part I, Item 1, of this Quarterly Report on Form 10-Q, which information is incorporated by reference into this Item 1.

As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (hereafter referred to as “Gavilon”) of alleged violations in 2011 by Gavilon of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by NGL 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 and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint relates to transactions between Gavilon and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon in 2011. The complaint seeks an order declaring that the RINs generated by Western Dubuque be declared invalid, that the defendants retire and replace such RINs and that the defendants pay statutory civil penalties. Consistent with our position against the previous EPA allegations, we deny the allegations in this civil complaint and intend to vigorously defend ourselves in the civil action. However, at this time NGL is unable to determine the outcome of this action or its significance to us.

Item 1A.Risk Factors

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016, as supplemented and updated by Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

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

None.

Item 3.Defaults Upon Senior Securities

Not applicable.

Item 4.Mine Safety Disclosures

Not applicable.

Item 5.Other Information

None.

83

Item 6.Exhibits

Exhibit Number		Exhibit
4.1	*	Limited Consent and Amendment No. 11 to Note Purchase Agreement, dated as of September 30, 2016, among the Partnership and the purchasers named therein
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) Condensed Consolidated Balance Sheets atSeptember 30, 2016andMarch 31, 2016, (ii) Condensed Consolidated Statements of Operations for the three months and six months endedSeptember 30, 2016and2015, (iii) Condensed Consolidated Statements of ComprehensiveIncome (Loss)for the three months and six months endedSeptember 30, 2016and2015, (iv) Condensed Consolidated Statement of Changes in Equity for thesix months endedSeptember 30, 2016, (v) Condensed Consolidated Statements of Cash Flows for thesix months endedSeptember 30, 2016and2015, and (vi) Notes to Condensed Consolidated Financial Statements.

84

SIGNATURES

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

	NGL ENERGY PARTNERS LP
	By:	NGL Energy Holdings LLC, its general partner
Date: November 4, 2016		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer
Date: November 4, 2016		By:	/s/ Robert W. Karlovich III
			Robert W. Karlovich III
			Chief Financial Officer

85

INDEX TO EXHIBITS

Exhibit Number		Exhibit
4.1	*	Limited Consent and Amendment No. 11 to Note Purchase Agreement, dated as of September 30, 2016, among the Partnership and the purchasers named therein
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) Condensed Consolidated Balance Sheets atSeptember 30, 2016andMarch 31, 2016, (ii) Condensed Consolidated Statements of Operations for the three months and six months endedSeptember 30, 2016and2015, (iii) Condensed Consolidated Statements of ComprehensiveIncome (Loss)for the three months and six months endedSeptember 30, 2016and2015, (iv) Condensed Consolidated Statement of Changes in Equity for thesix months endedSeptember 30, 2016, (v) Condensed Consolidated Statements of Cash Flows for thesix months endedSeptember 30, 2016and2015, and (vi) Notes to Condensed Consolidated Financial Statements.

86

EX-4.1

Exhibit 4.1

LIMITED CONSENT AND AMENDMENT NO. 11 TO NOTE PURCHASE AGREEMENT

THIS LIMITED CONSENT AND AMENDMENT NO. 11 TO NOTE PURCHASE AGREEMENT, dated as of September 30, 2016, but effective as of the Effective Date (as defined in Section 3 hereof) (this “Amendment”), to the Note Purchase Agreement dated as of June 19, 2012, as amended by Amendment No. 1 thereto dated as of January 15, 2013, Amendment No. 2 thereto dated as of May 8, 2013, Amendment No. 3 thereto dated as of September 30, 2013, Amendment No. 4 thereto dated as of November 5, 2013, Amendment No. 5 thereto dated as of December 23, 2013, Amendment No. 6 thereto dated as of June 30, 2014, Amendment No. 7 thereto dated as of December 19, 2014, Amendment No. 8 thereto dated as of May 1, 2015, Amendment No. 9 thereto dated as of December 28, 2015, and Amendment No. 10 thereto dated as of February 9, 2016 (such note purchase agreement, as so amended, being referred to herein as the “Existing Note Purchase Agreement” and as the same shall be further amended hereby, the “Note Purchase Agreement”), is among NGL Energy Partners LP, a Delaware limited partnership (the “Company”), the Guarantors (solely with respect to Section 6(c) hereof) and the holders of Notes listed on the signature pages hereto (collectively, the “Noteholders”).

RECITALS:

A.    The Company and the Purchasers party thereto have previously entered into the Existing Note Purchase Agreement. Capitalized terms used and not otherwise defined herein shall have the respective meanings ascribed to them in the Existing Note Purchase Agreement.

B.    The Guarantors entered into that certain Guaranty Agreement dated as of June 19, 2012 (as heretofore amended, supplemented or otherwise modified, the “Guaranty Agreement”).

C.    The Company has requested certain amendments to the Existing Note Purchase Agreement as more fully described herein below.

D.    The Noteholders have agreed to such amendments, subject to the performance and observance in full of each of the covenants, terms and conditions, and in reliance upon all of the representations and warranties of the Company, set forth herein.

NOW, THEREFORE, in consideration of the premises and the covenants, terms, conditions, representations and warranties herein contained, the parties hereto hereby agree as follows:

Section 1. AMENDMENTS TO EXISTING NOTE PURCHASE AGREEMENT. Subject to the covenants, terms and conditions set forth herein and in reliance upon the representations and warranties of the Company herein contained, the Company and the Noteholders hereby agree to amend the Existing Note Purchase Agreement as set forth below, effective as of the Effective Date:

(a)Amendment to Section 7.2 of the Existing Note Purchase Agreement. Section 7.2(a) of the Existing Note Purchase Agreement is hereby amended by inserting the text “or Test Two Failure” after each reference to “Test One Failure” contained in such Section.

(b)Amendment to Section 8.9 of the Existing Note Purchase Agreement. Section 8.9 of the Existing Note Purchase Agreement is hereby amended and restated to read in its entirety as follows:

“Section 8.9. Additional Interest. With respect to all Notes:

(a)    upon the occurrence of a Trigger Event, (i) (A) solely with respect to a Test One Failure, the interest rate with respect to the Notes shall be immediately and automatically increased by 0.50% per annum for the remaining life of the Notes (subject to the provisions of Section 8.9(b)), and (B) with respect to a Test Two Failure, the interest rate with respect to the Notes shall be immediately and automatically increased by an additional 0.50% per annum (which such increase will be in addition to the then existing increase specified in clause (A) of this Section 8.9(a)(i) for an aggregate increase in the interest rate with respect to the Notes of 1.00% per annum) for the remaining life of the Notes (subject to the provisions of Section 8.9(b)) and (ii) the Company shall, on the next date on which interest payments are due to be made under the terms of the Notes (each such date, an “Interest Payment Date”) following any such Trigger Event, pay to each holder of such Notes a one-time payment for such Trigger Event in an amount equal to the product of (x)(I) if such Trigger Event resulted solely as a result of a Test One Failure, 0.50%, (II) if such

1

Trigger Event resulted solely as a result of a Test Two Failure, 0.50% (i.e., a Test One Failure had occurred in a prior period and no Reset Event had occurred for such Test One Failure) and (III) if such Trigger Event exists as a result of both a Test One Failure and a Test Two Failure, 1.00%, (y) the aggregate principal amount of Notes held by such holder or its predecessor holder as of the end of the most recently completed fiscal quarter of the Company for which the Company is required to deliver financial statements pursuant to Sections 7.1 (a) or (b), as the case may be, and giving effect to any reduction in principal of the Notes since the end of such fiscal quarter, and (z) a fraction, the numerator of which is the number of days from and including the end of the most recently completed fiscal quarter described in the immediately preceding clause (y) to, but excluding the date of, the occurrence of the Trigger Event and the denominator of which is 360;

(b)    if, at any time following (I) a Trigger Event where a Test Two Failure existed, no Test Two Failure shall continue to exist or (II) a Trigger Event where a Test One Failure existed, no Test One Failure shall continue to exist (each a “Reset Event”; provided, however, that such Reset Event shall be deemed to occur on the date upon which the Company delivers its quarterly or annual financial statements and accompanying certificates pursuant to Sections 7.1 and 7.2 demonstrating satisfaction of the aforementioned conditions), (i) the interest rate with respect to the Notes shall be immediately and automatically reduced by 0.50% (or, with respect to a Reset Event occurring as a result of the satisfaction of both clauses (I) and (II) above, 1.00%) per annum for the remaining life of the Notes (subject to the provisions of Sections 8.9(a) and (c)) and (ii) each holder of Notes shall apply a one-time credit, on the next Interest Payment Date of the Notes following such Reset Event, to the accrued interest owed by the Company with respect to the Notes by an amount equal to the product of (x)(A) if only one of the above clauses (I) and (II) caused the Reset Event, 0.50% or (B) if both of the above clauses (I) and (II) caused the Reset Event, 1.00%, (y) the aggregate principal amount of Notes held by such holder or its predecessor holder as of the end of the most recently completed fiscal quarter of the Company for which the Company is required to deliver financial statements pursuant to Section 7.1 (a) or (b), as the case may be, and giving effect to any reduction in principal of the Notes since the end of such fiscal quarter, and (z) a fraction, the numerator of which is the number of days from and including the end of the most recently completed fiscal quarter described in the immediately preceding clause (y) to, but excluding the date of, the occurrence of the Reset Event and the denominator of which is 360;

(c)    notwithstanding anything in this Section 8.9 to the contrary, another Trigger Event may follow a Reset Event, in which case the provisions of Sections 8.9(a) and (b) shall apply; and

(d)    for the avoidance of doubt and notwithstanding anything in this Section 8.9 or otherwise in this Agreement to the contrary, upon the occurrence and during the continuance of an Event of Default, the interest rate with respect to the Notes shall be at the default rate as set forth in clause (b) of the first paragraph of each Note, and such rate shall be automatically increased by the applicable rate specified in Section 8.9(a) for all periods during which a Trigger Event continues to exist.”

(c)    Amendment to clause (a) of Section 10.6 (Financial Covenants) of the Existing Note Purchase Agreement. Clause (a) of Section 10.6 (Financial Covenants) of the Existing Note Purchase Agreement is hereby amended and restated in its entirety as follows:

“(a)    Commencing with the fiscal quarter ended June 30, 2016, the Company will not permit the Leverage Ratio of the Note Parties to be greater than 4.75 to 1.00 as of the last day of any fiscal quarter. Commencing with the fiscal quarter ending December 31, 2018, the Company will not permit the Leverage Ratio of the Note Parties to be greater than 4.25 to 1.00 as of the last day of any fiscal quarter.”

(d)    Amendment to clause Section 10 (Negative Covenants) of the Existing Note Purchase Agreement. Section 10 (Negative Covenants) of the Existing Note Purchase Agreement is hereby amended by adding a new Section 10.21 in its appropriate numerical order to read in its entirety as follows:

“Section 10.21. Credit Agreement Financial Covenants. The Company shall not, and shall not permit, the financial covenants contained in Section 7.11 (or any successor Section) of the Credit Agreement and the defined terms referenced therein to be amended or otherwise modified in any significant manner that is different than the financial covenants contained in Section 10.6 of this Agreement and the defined terms referenced therein without providing the holders with (a) at least 20 Business Days prior written notice of the Company’s proposed amendments or modifications to such financial covenants and/or definitions and (b) an opportunity to review and discuss such proposed amendments and modifications with a Financial Officer of the Company prior to their effectiveness. For purposes of this Section 10.21, any such amendment or modification that (1)(x) introduces a separate maximum secured leverage ratio in addition to a maximum total leverage ratio or (y) modifies the working capital loan exception in the numerator of such leverage ratio shall be deemed “significant” and (2)

2

increases or decreases the maximum total leverage ratio shall not be deemed “significant.” Regardless of whether any such amendment or modification is “significant” for purposes of this Section 10.21, the holders expressly reserve their rights under Section 10.20 with respect to any amendment or modification of the Credit Agreement.”

(e)    Amendments to Schedule B to the Existing Note Purchase Agreement. Schedule B to the Existing Note Purchase Agreement is hereby amended as follows:

(i) The definition of “Consolidated EBITDA” is hereby amended and by amending and restating in its entirety clause (B) in the final proviso of such definition, as follows:

“(B) with regard to each Major Permitted Business Expansion Project, excluding the Grand Mesa Project, such pro forma adjustment (x) shall be based upon forecasted income to be derived from binding, non-contingent contracts less appropriate direct and indirect costs to realize such income and (y) when aggregated with all pro forma adjustments attributable to Major Permitted Business Expansion Projects, excluding the Grand Mesa Project, shall not exceed 15.00% of the Consolidated EBITDA reflected in the most recently delivered Compliance Certificate, net of any actual Consolidated EBITDA realized from such Major Permitted Business Expansion Projects (excluding the Grand Mesa Project) and without giving effect to increases in such Consolidated EBITDA arising from such Major Permitted Business Expansion Projects for such pro forma period; provided that with respect to the Grand Mesa Project, Consolidated EBITDA shall be based on (i) forecasted income to be derived from binding, non-contingent contracts less appropriate direct and indirect costs to realize such income and (ii) income from FERC required walk-up volume capped at 10,000 bpd (subject to the limitation that the sum of the immediately preceding clauses (i) and (ii) shall not exceed $140,000,000 for any four quarters ending on or prior to the date of determination) multiplied by the applicable GMP Completion Percentage as of the end of such period; provided, further, that to the extent the Grand Mesa Project is not complete as of December 31, 2016, the contribution of the Grand Mesa Project to Consolidated EBITDA will be reduced by 25% per quarter for each quarter commencing with the fiscal quarter ending December 31, 2016.”

(ii) The definition of “GMP Completion Percentage” is hereby amended and restated in its entirety as follows:

“GMP Completion Percentage” with respect to the determination of Consolidated EBITDA for any period, the percentage of completion for the Grand Mesa Project determined as the quotient (expressed as a percentage) of the costs incurred by the Note Parties as of the end of the applicable period over the estimated total project cost of the Grand Mesa Project at such time. As of the Amendment No. 11 Effective Date, the Note Parties have incurred costs in connection with the Grand Mesa Project in an amount equal to $770,000,000 and the estimated total project cost as of such date is $831,000,000.

(iii) The definition of “Test Two Failure” is hereby added to Schedule B of the Existing Note Purchase Agreement in appropriate alphabetical order to read in its entirety as follows:

“Test Two Failure” shall mean, at any time, the existence of a Leverage Ratio (measured quarterly as of the end of each fiscal quarter) which is greater than 4.50 to 1.00.”

(iv) The definition of “Trigger Event” in Schedule B of the Existing Note Purchase Agreement is hereby amended by inserting the text “or Test Two Failure” after each reference to “Test One Failure” contained in such definition.

Section 2. LIMITED CONSENT. Subject to the satisfaction of the conditions set forth in Section 3 below, the Noteholders hereby consent to (i) the Collateral Agent’s release of its Lien on any Collateral in accordance with Section 8.17 of the Security Agreement and any other applicable provision of any Security Document, providedthat (a) the sale, lease, transfer or other disposition of such Collateral is permitted pursuant to the terms of the Note Purchase Agreement, (b) the Company provides the Noteholders prior written notice of such release, which notice (I) shall specify the Section or Sections of the Note Purchase Agreement permitting the Company to sell, lease, transfer or otherwise dispose of such Collateral and (II) may be included in any officer’s certificate referenced in the following clause (c), and (c) the Company shall provide the Noteholders a copy of any officer’s certificate delivered to the Collateral Agent in connection with such release (including, without limitation, any officer’s certificate delivered pursuant to Section 8.17(a)(ii) of the Security Agreement); provided that delivery by the Company of any such notice and certificate to the outside counsel for the Noteholders shall constitute delivery to the Noteholders for the purposes of this limited

3

consent, and (ii) the Collateral Agent’s execution and delivery of any Security Document, or any amendment or supplement to any Security Document, solely for purposes of (x) granting or perfecting a security interest in or lien on assets or property of any Note Party in favor of the Collateral Agent, for the benefit of the Noteholders and the other Secured Parties, or (y) releasing a Lien permitted to be released pursuant to clause (i) above, provided that in the case of each of clause (x) and (y), outside counsel for the Noteholders are provided a draft of any such Security Document, amendment or supplement and are afforded a reasonable opportunity to review and comment upon the same before its execution. The foregoing consent shall serve as the written notice and direction from the Required Holders to the Collateral Agent (I) pursuant to Section 8.17 of the Security Agreement and Section 21 of the Intercreditor Agreement in connection with any such release of Collateral and (II) pursuant to Section 23 of the Intercreditor Agreement in connection with the execution and delivery of any such future Security Documents, amendments or supplements; provided that the Administrative Agent, Technical Agent and/or requisite number of Lenders, as applicable, has or have also provided their written notice and direction, or such written notice and direction has been given automatically under the Loan Documents (as defined in the Credit Agreement), in connection with any such release or execution and delivery. Subject to the foregoing, nothing contained in this Amendment shall be construed as a waiver by the Noteholders of any covenant or provision of the Note Purchase Agreement or the other Note Documents, and the failure of the Noteholders at any time or times hereafter to require strict performance of any provision thereof shall not waive, affect or diminish any right of the Noteholders to thereafter demand strict compliance therewith. The Noteholders hereby reserve all rights granted under the Note Purchase Agreement and the other Note Documents. The parties hereby agree that the Collateral Agent is an express third party beneficiary of this limited consent and, as such, shall be permitted to rely on such limited consent with respect to the release of its Lien on any Collateral in accordance with Section 8.17 of the Security Agreement and any other applicable provision of any Security Document and the Collateral Agent’s execution and delivery of any Security Document, or any amendment or supplement to any Security Document.

Section 3. EFFECTIVENESS OF AMENDMENTS. Upon the satisfaction of each of the conditions provided immediately below in this Section 3 (with each of the documents referred to below being in form and substance satisfactory to the Required Holders and in full force and effect), the amendments set forth in Section 1 of this Amendment shall be deemed to be effective as of June 30, 2016 (the Effective Date”):

(a)Execution and Delivery of this Amendment. The Noteholders shall have received a copy of this Amendment duly executed and delivered by the Company and the Guarantors, and by the Noteholders constituting the Required Holders.

(b)Representations and Warranties. Each of the representations and warranties of the Company made in this Amendment shall be true and correct on and as of the Effective Date.

(c)Payment of Amendment Fee. The Company shall have paid a fee to each Noteholder equal to 0.10% multiplied by the aggregate outstanding principal amount of the Notes held by such Noteholder.

(d)Certificates and Approvals. The Company shall deliver a certificate of its Secretary or Assistant Secretary attaching and certifying copies of (i) the Organizational Documents of the Company, (ii) a corporate good standing certificate with respect to the Company from its jurisdiction of organization, dated as of a recent date, (iii) resolutions of the governing body of the Company authorizing the execution, delivery and performance of this Amendment, the Note Purchase Agreement (as amended hereby) and all related documents (collectively, the “Transaction Documents”) and (iv) the name, title and true signature of each officer of the Company authorized to execute the Transaction Documents.

(e)Legal Opinion. The Noteholders shall have received a favorable opinion of Winston & Strawn LLP, counsel for the Company, in form and substance satisfactory to the Noteholders, as to (i) the due authorization, execution and delivery of this Amendment by the Company and (ii) the enforceability of this Amendment against the Company. The Company hereby directs such counsel to deliver such opinion and understands and agrees that each Noteholder will and hereby is authorized to rely on such opinion.

(f)Proceedings and Documents. All corporate and other proceedings pertaining directly to this Amendment and all documents and instruments directly incident to this Amendment shall be satisfactory to the Required Holders and their special counsel, and the Noteholders and their special counsel shall have received all such counterpart originals or certified or other copies of such documents as the Required Holders or such special counsel may reasonably request.

Section 4. REPRESENTATIONS AND WARRANTIES; NO DEFAULT. To induce the Noteholders to enter into this Amendment, the Company (by delivery of its counterpart to this Amendment) hereby (i) represents and warrants to the Noteholders that after giving effect to this Amendment and the contemporaneous amendments to the Credit Agreement, its representations and warranties contained in the Note Purchase Agreement are true and correct in all material respects (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect” or a like qualification, which shall be correct in all respects) on and as of the Effective Date with the same effect as though made on and as of the Effective Date, except

4

to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties were true and correct in all material respects (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect” or a like qualification, which were true in all respects) as of such earlier date), (ii) represents and warrants to the Noteholders that in connection with this Amendment and all other documents delivered in connection herewith it (x) has the requisite power and authority to make, deliver and perform the same, (y) has taken all necessary limited partnership action to authorize its execution, delivery and performance of the same, and (z) has duly executed and delivered the same and (iii) except to the extent waived herein, certifies that no Default or Event of Default exists under any of the Note Documents (both immediately before and after giving effect to this Amendment) or will result from the making of this Amendment.

Section 5. EXPENSES. The Company will promptly (and in any event within thirty (30) days of receiving any statement or invoice therefor) pay all reasonable out-of-pocket expenses and costs incurred by the Noteholders relating to this Amendment, including, but not limited to, the reasonable fees and disbursements of Baker Botts L.L.P., incurred in connection with the preparation, negotiation and delivery of this Amendment, and all other related documentation. This Section 5 shall not be construed to limit the Company’s obligations under Section 15.1 of the Existing Note Purchase Agreement.

Section 6. MISCELLANEOUS.

(a)GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

(b)Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument. Each counterpart may consist of a number of copies hereof, each signed by less than all, but together signed by all, the parties hereto. Delivery of this Amendment may be made by telecopy or electronic transmission of a duly executed counterpart copy hereof; provided that any such delivery by electronic transmission shall be effective only if transmitted in .pdf format, .tif format or other format in which the text is not readily modifiable by any recipient thereof.

(c)Affirmation of Obligations. Notwithstanding that such consent is not required under the Guaranty Agreement, or any of the other Note Documents to which it is a party, each of the Guarantors consents to the execution and delivery of this Amendment by the parties hereto. As a material inducement to the undersigned to amend the Existing Note Purchase Agreement, each of the Guarantors (i) acknowledges and confirms the continuing existence, validity and effectiveness of the Guaranty Agreement and each of the other Note Documents to which it is a party and (ii) agrees that the execution, delivery and performance of this Amendment shall not in any way release, diminish, impair, reduce or otherwise affect its obligations thereunder.

(d)Note Document. This Amendment is a Note Document and all of the provisions of the Note Purchase Agreement which apply to Note Documents apply hereto. Except as expressly provided hereby, all of the terms and provisions of the Note Purchase Agreement and the other Note Documents are and shall remain in full force and effect. The amendments and consents contained herein shall not be construed as a waiver or amendment of any other provision of the Note Purchase Agreement or any other Note Document or for any purpose, except as expressly set forth herein, or a consent to any further or future action on the part of any Note Party that would require the waiver or consent of the Noteholders.

(Remainder of Page Intentionally Left Blank; Signature Pages Follow)

5

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers effective as of the Effective Date.

NGL ENERGY PARTNERS LP

By: NGL Energy Holdings LLC,

its general partner

By: /s/ Robert “Trey” W. Karlovich III

Name: Robert “Trey” W. Karlovich III

Title: Chief Financial Officer

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

The foregoing is hereby agreed to as of the date hereof:

NOTEHOLDERS:

THE PRUDENTIAL INSURANCE COMPANY

OF AMERICA, as a Noteholder

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Vice President

PRUCO LIFE INSURANCE COMPANY,

as a Noteholder

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Assistant Vice President

UNIVERSAL PRUDENTIAL ARIZONA

REINSURANCE COMPANY, as a Noteholder

By:    PGIM, Inc.,

as investment manager

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Vice President

PRUDENTIAL ARIZONA REINSURANCE

CAPTIVE COMPANY, as a Noteholder

By:    PGIM, Inc.,

as investment manager

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Vice President

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

PRUDENTIAL ARIZONA REINSURANCE

UNIVERSAL COMPANY, as a Noteholder

By:    PGIM, Inc.,

as investment manager

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Vice President

PRUDENTIAL RETIREMENT INSURANCE AND

ANNUITY COMPANY, as a Noteholder

By:    PGIM, Inc.,

as investment manager

By: /s/ Christopher L. Halloran

Name: Christopher L. Halloran

Title: Vice President

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger to

AMERICAN GENERAL LIFE AND ACCIDENT INSURANCE COMPANY)

AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger to

AMERICAN GENERAL LIFE INSURANCE COMPANY OF DELAWARE)

AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger to

SUNAMERICA ANNUITY AND LIFE ASSURANCE COMPANY)

THE UNITED STATES LIFE INSURANCE COMPANY IN THE CITY OF NEW YORK

COMMERCE AND INDUSTRY INSURANCE COMPANY

NEW HAMPSHIRE INSURANCE COMPANY

AIG PROPERTY CASUALTY COMPANY (f/k/a CHARTIS PROPERTY CASUALTY COMPANY)

By:    AIG ASSET MANAGEMENT (U.S.), LLC, Investment Adviser

By: /s/ Curtis F. Sullivan

Name: Curtis F. Sullivan    

Title: Vice President

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

TEACHERS INSURANCE AND ANNUITY ASSOCIATION OF

AMERICA, as a Noteholder

By: /s/ Lisa M. Ferraro

Name: Lisa M. Ferraro

Title: Managing Director

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

SUN LIFE ASSURANCE COMPANY OF CANADA,

as a Noteholder

By: /s/ Steve Theofanis

Name: Steve Theofanis    

Title: Managing Director

Private Fixed Income

By: /s/ Maurice Primeau

Name: Maurice Primeau

Title: Managing Director

Private Fixed Income

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

Agreed to and acknowledged by the undersigned solely with respect to Section 6(c) hereof:

GUARANTORS:                ANTICLINE DISPOSAL, LLC

BLUE GRAMA LAND CORPORATION

CENTENNIAL ENERGY, LLC

CENTENNIAL GAS LIQUIDS ULC

GRAND MESA PIPELINE, LLC

HICKSGAS, LLC

HIGH SIERRA CRUDE OIL & MARKETING, LLC

HIGH SIERRA ENERGY, LP (BY High Sierra Energy GP, LLC, its general partner)

HIGH SIERRA ENERGY MARKETING, LLC

HIGH SIERRA ENERGY OPERATING, LLC

NGL CRUDE CANADA HOLDINGS, LLC

NGL CRUDE CUSHING, LLC

NGL CRUDE LOGISTICS, LLC

NGL CRUDE PIPELINES, LLC

NGL CRUDE TERMINALS, LLC

NGL CRUDE TRANSPORTATION, LLC

NGL ENERGY HOLDINGS II, LLC

NGL ENERGY LOGISTICS, LLC

NGL ENERGY OPERATING LLC

NGL LIQUIDS, LLC

NGL-MA, LLC

NGL-MA REAL ESTATE, LLC

NGL MARINE, LLC

NGL MILAN INVESTMENTS, LLC

NGL-NE REAL ESTATE, LLC

NGL PROPANE, LLC

NGL SHIPPING AND TRADING, LLC

NGL SUPPLY TERMINAL COMPANY, LLC

NGL SUPPLY WHOLESALE, LLC

NGL WATER SOLUTIONS BAKKEN, LLC

NGL WATER SOLUTIONS EAGLE FORD, LLC

NGL WATER SOLUTIONS, LLC

NGL WATER SOLUTIONS PERMIAN, LLC

NGL WATER SOLUTIONS DJ, LLC

NGL WATER SOLUTIONS MID-CONTINENT, LLC

OSTERMAN PROPANE, LLC

TRANSMONTAIGNE LLC

TRANSMONTAIGNE PRODUCT SERVICES LLC

TRANSMONTAIGNE SERVICES LLC

SAWTOOTH NGL CAVERNS, LLC

NGL SUPPLY TERMINAL SOLUTIONS

MINING, LLC

By: /s/ Robert “Trey” W. Karlovich III

Name: Robert “Trey” W. Karlovich III

Title: Chief Financial Officer

Signature Page to Limited Consent and Amendment No. 11 to Note Purchase Agreement

EX-12.1

Exhibit 12.1

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS (LOSS) TO FIXED CHARGES

AND COMBINED FIXED CHARGES AND PREFERRED UNIT DISTRIBUTIONS

(In thousands, except ratio amounts)

	Six Months Ended September 30,			Year Ended March 31,
	2016			2016			2015 (1)			2014			2013			2012
EARNINGS (LOSS):
Income (loss) before income taxes	$	117,017		$	(187,464	)	$	46,571		$	49,695		$	50,065		$	8,465
(Income) loss before income taxes attributable to noncontrolling interests	(5,774		)	(11,832		)	(12,887		)	(1,103		)	(250		)	12
Fixed charges	74,233			146,401			151,956			91,622			66,824			9,354
Total earnings (loss)	$	185,476		$	(52,895	)	$	185,640		$	140,214		$	116,639		$	17,831
FIXED CHARGES:
Interest expense	$	63,880		$	133,089		$	110,123		$	58,854		$	32,994		$	7,620
(Gain) loss on early extinguishment of debt	(8,614		)	(28,532		)	—			—			5,769			—
Portion of rental expense estimated to relate to interest (2)	18,967			41,844			41,833			32,768			28,061			1,734
Fixed charges	$	74,233		$	146,401		$	151,956		$	91,622		$	66,824		$	9,354
PREFERRED UNIT DISTRIBUTIONS	8,245			—			—			—			—			—
Combined fixed charges and preferred unit distributions	$	82,478		$	146,401		$	151,956		$	91,622		$	66,824		$	9,354
Ratio of earnings to fixed charges (3)	2.50			—			1.22			1.53			1.75			1.91
Ratio of earnings to combined fixed charges and preferred unit distributions (3)	2.25			—			1.22			1.53			1.75			1.91

(1) We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31, 2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016).

(2) Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.

(3) The ratios were less than 1:1 for the year ended March 31, 2016. NGL Energy Partners LP would have needed to generate an additional $199.3 million of earnings to achieve a ratio of 1:1.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, H. Michael Krimbill, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of NGL Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2016	/s/ H. Michael Krimbill
	H. Michael Krimbill
	Chief Executive Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Robert W. Karlovich III, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of NGL Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2016	/s/ Robert W. Karlovich III
	Robert W. Karlovich III
	Chief Financial Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

EX-32.1

Exhibit 32.1

CERTIFICATIONPURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report of NGL Energy Partners LP (the “Partnership”) on Form 10-Q for the fiscal quarter endedSeptember 30, 2016as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, H. Michael Krimbill, Chief Executive Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 4, 2016	/s/ H. Michael Krimbill
	H. Michael Krimbill
	Chief Executive Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATIONPURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report of NGL Energy Partners LP (the “Partnership”) on Form 10-Q for the fiscal quarter endedSeptember 30, 2016as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert W. Karlovich III, Chief Financial Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 4, 2016	/s/ Robert W. Karlovich III
	Robert W. Karlovich III
	Chief Financial Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	6 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document and Entity Information
Entity Registrant Name	NGL Energy Partners LP
Entity Central Index Key	0001504461
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--03-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		107,444,272
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2

XML

Unaudited Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Mar. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 23,427	$ 28,176
Accounts receivable-trade, net of allowance for doubtful accounts of $5,850 and $6,928, respectively	592,074	521,014
Accounts receivable-affiliates	3,540	15,625
Inventories	520,340	367,806
Prepaid expenses and other current assets	110,918	95,859
Total current assets	1,250,299	1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $324,364 and $266,491, respectively	1,755,416	1,649,572
GOODWILL	1,467,955	1,315,362
INTANGIBLE ASSETS, net of accumulated amortization of $356,314 and $316,878, respectively	1,190,147	1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	190,662	219,550
LOAN RECEIVABLE-AFFILIATE	1,700	22,262
OTHER NONCURRENT ASSETS	217,739	176,039
Total assets	6,073,918	5,560,155
CURRENT LIABILITIES:
Accounts payable-trade	512,104	420,306
Accounts payable-affiliates	6,244	7,193
Accrued expenses and other payables	184,634	214,426
Advance payments received from customers	87,825	56,185
Current maturities of long-term debt	8,046	7,907
Total current liabilities	798,853	706,017
LONG-TERM DEBT, net of debt issuance costs of $13,482 and $15,500, respectively, and current maturities	3,063,008	2,912,837
OTHER NONCURRENT LIABILITIES	198,001	247,236
COMMITMENTS AND CONTINGENCIES (NOTE 10)
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 0 preferred units issued and outstanding, respectively	58,742	0
EQUITY:
General partner, representing a 0.1% interest, 107,360 and 104,274 notional units, respectively	(50,735)	(50,811)
Limited partners, representing a 99.9% interest, 107,252,272 and 104,169,573 common units issued and outstanding, respectively	1,977,596	1,707,326
Accumulated other comprehensive loss	(642)	(157)
Noncontrolling interests	29,095	37,707
Total equity	1,955,314	1,694,065
Total liabilities, convertible preferred units and equity	$ 6,073,918	$ 5,560,155

XML

Unaudited Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Mar. 31, 2016	Sep. 30, 2016
Accounts receivable - trade, allowance for doubtful accounts	$ 6,928	$ 5,850
PROPERTY, PLANT AND EQUIPMENT, accumulated depreciation	266,491	324,364
INTANGIBLE ASSETS, accumulated amortization	316,878	356,314
LONG-TERM DEBT, debt issuance costs	$ 15,500	$ 13,482
General partner interest	0.10%	0.10%
General partner, notional units outstanding (in units)	104,274	107,360
Limited partners interest	99.90%	99.90%
Limited partners, common units issued (in units)	104,169,573	107,252,272
Limited partners, common units outstanding (in units)	104,169,573	107,252,272
Class A Convertible Preferred Units
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, units issued (in units)	0	19,942,169
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, units outstanding (in units)	0	19,942,169

XML

Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES:
Crude Oil Logistics	$ 349,885	$ 1,007,578	$ 775,836	$ 2,335,362
Water Solutions	39,733	47,494	75,486	101,787
Liquids	234,260	258,992	439,309	507,977
Retail Propane	51,090	53,206	111,477	117,653
Refined Products and Renewables	2,370,322	1,825,925	4,364,885	3,668,885
Other	248	0	515	0
Total Revenues	3,045,538	3,193,195	5,767,508	6,731,664
COST OF SALES:
Crude Oil Logistics	340,518	982,719	745,748	2,274,711
Water Solutions	(1,807)	(8,567)	3,394	(4,960)
Liquids	209,283	221,115	400,275	453,391
Retail Propane	20,691	20,879	45,511	50,443
Refined Products and Renewables	2,359,932	1,789,680	4,300,019	3,554,792
Other	113	0	223	0
Total Cost of Sales	2,928,730	3,005,826	5,495,170	6,328,377
OPERATING COSTS AND EXPENSES:
Operating	73,255	97,630	148,427	203,220
General and administrative	27,926	29,298	69,797	91,779
Depreciation and amortization	50,603	56,761	99,509	116,592
Loss (gain) on disposal or impairment of assets, net	852	1,291	(203,467)	1,712
Revaluation of liabilities	0	(15,909)	0	(27,104)
Operating (Loss) Income	(35,828)	18,298	158,072	17,088
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	53	2,432	447	11,150
Revaluation of investments	0	0	(14,365)	0
Interest expense	(33,442)	(31,571)	(63,880)	(62,373)
Gain on early extinguishment of liabilities	938	0	30,890	0
Other income, net	2,081	1,955	5,853	780
(Loss) Income Before Income Taxes	(66,198)	(8,886)	117,017	(33,355)
INCOME TAX (EXPENSE) BENEFIT	(460)	2,786	(922)	2,248
Net (Loss) Income	(66,658)	(6,100)	116,095	(31,107)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	59	(3,497)	(5,774)	(7,847)
NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	(66,599)	(9,597)	110,321	(38,954)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(8,668)	0	(12,052)	0
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	45	(16,185)	(158)	(31,559)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$ (75,222)	$ (25,782)	$ 98,111	$ (70,513)
BASIC (LOSS) INCOME PER COMMON UNIT (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.93	$ (0.67)
DILUTED INCOME LOSS PER COMMON UNIT (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.91	$ (0.67)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING (in units)	106,186,389	105,189,463	105,183,556	104,542,427
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING (in units)	106,186,389	105,189,463	107,997,549	104,542,427

XML

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ (66,658)	$ (6,100)	$ 116,095	$ (31,107)
Other comprehensive loss	(333)	(19)	(485)	(27)
Comprehensive (loss) income	$ (66,991)	$ (6,119)	$ 115,610	$ (31,134)

XML

Unaudited Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Thousands	Total	Class A Convertible Preferred Units	Accumulated Other Comprehensive Loss	Noncontrolling Interests	General Partner	Limited Partner	Limited Partner Class A Convertible Preferred Units	Limited Partner Common units
Beginning Balance (in units) at Mar. 31, 2016								104,169,573
Beginning Balance at Mar. 31, 2016	$ 1,694,065		$ (157)	$ 37,707	$ (50,811)	$ 1,707,326
Increase (Decrease) in Partnership Capital
Distributions	(86,457)			(2,750)	(141)	(83,566)
Contributions	524			966	59	(501)
Business combinations (in units)								218,617
Business combinations	3,969				0	3,969
Purchase of noncontrolling interest (Notes 4 and 15)	(12,817)			(12,602)		(215)
Equity issued pursuant to incentive compensation plan (in units)								2,340,082
Equity issued pursuant to incentive compensation plan	54,781				0	54,781
Common units issued, net of offering costs (in units)								524,000
Common units issued, net of offering costs	9,383				0	9,383
Allocation of value to beneficial conversion feature of Class A convertible preferred units		$ 131,534					$ 131,534
Issuance of warrants	48,550					48,550
Accretion of beneficial conversion feature of Class A convertible preferred units		$ (3,808)					$ (3,808)
Net (loss) income	116,095			5,774	158	110,163
Other comprehensive loss	(485)		(485)
Other	(20)			0		(20)
Ending Balance (in units) at Sep. 30, 2016								107,252,272
Ending Balance at Sep. 30, 2016	1,955,314		(642)	29,095	(50,735)	1,977,596
Increase (Decrease) in Partnership Capital
Business combinations	$ 3,969
Common units issued, net of offering costs (in units)	524,000
Net (loss) income	$ (66,658)
Other comprehensive loss	(333)
Ending Balance (in units) at Sep. 30, 2016								107,252,272
Ending Balance at Sep. 30, 2016	$ 1,955,314		$ (642)	$ 29,095	$ (50,735)	$ 1,977,596

XML

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
OPERATING ACTIVITIES:
Net (loss) income	$ 116,095	$ (31,107)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation and amortization, including amortization of debt issuance costs	108,133	124,551
Gain on early extinguishment or revaluation of liabilities	(30,890)	(27,104)
Non-cash equity-based compensation expense	32,994	51,482
(Gain) loss on disposal or impairment of assets, net	(203,467)	1,712
Provision for doubtful accounts	(122)	3,046
Net commodity derivative loss (gain)	44,966	(44,534)
Equity in earnings of unconsolidated entities	(447)	(11,150)
Distributions of earnings from unconsolidated entities	42	11,593
Revaluation of investments	14,365	0
Other	(485)	(8)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(54,069)	322,230
Inventories	(151,507)	34,333
Other current and noncurrent assets	(44,798)	(7,322)
Accounts payable-trade and affiliates	90,496	(272,322)
Other current and noncurrent liabilities	22,295	18,695
Net cash (used in) provided by operating activities	(56,399)	174,095
INVESTING ACTIVITIES:
Capital expenditures	(159,680)	(222,276)
Purchases of pipeline capacity allocations	(41,953)	0
Acquisitions of businesses, including acquired working capital, net of cash acquired	(113,297)	(150,546)
Cash flows from commodity derivatives	(25,015)	43,032
Proceeds from sales of assets	396	3,567
Proceeds from sale of TLP common units	112,370	0
Investments in unconsolidated entities	0	(6,926)
Distributions of capital from unconsolidated entities	5,233	8,207
Loan for natural gas liquids facility	0	(3,913)
Payments on loan for natural gas liquids facility	4,324	3,546
Loan to affiliate	(1,700)	(15,621)
Payments on loan to affiliate	655	0
Payment to terminate development agreement	(16,875)	0
Net cash used in investing activities	(235,542)	(340,930)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	770,000	1,354,700
Payments on revolving credit facilities	(595,500)	(1,006,600)
Repurchases of senior notes	(15,129)	0
Payments on other long-term debt	(4,423)	(2,344)
Debt issuance costs	(320)	(1,380)
Contributions from partners	(442)	45
Contributions from noncontrolling interest owners	966	6,613
Distributions to partners	(83,707)	(154,824)
Distributions to noncontrolling interest owners	(2,750)	(17,780)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018	0
Proceeds from sale of common units, net of offering costs	9,383	0
Payments for the early extinguishment of liabilities	(25,884)	0
Taxes paid on behalf of equity incentive plan participants	0	(19,083)
Common unit repurchases	0	(3,650)
Other	(20)	(112)
Net cash provided by financing activities	287,192	155,585
Net decrease in cash and cash equivalents	(4,749)	(11,250)
Cash and cash equivalents, beginning of period	28,176	41,303
Cash and cash equivalents, end of period	$ 23,427	$ 30,053

XML

Organization and Operations

6 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Operations

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.AtSeptember 30, 2016, our operations include:

• Our Crude Oil Logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests intwocrude oil pipelines,purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

• Our Water Solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities,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 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 its18owned 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, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in27states and the District of Columbia.

• Our Refined Products and Renewables segment, which 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.

Recent Developments

On February 1, 2016, we completed the sale of our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners (“ArcLight”). As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. See Note 2 for a discussion of the sale. As TLP was previously a consolidated entity, our condensed consolidated statements of operations for the three months and six months endedSeptember 30, 2015 included three months and six months, respectively, of TLP’s operations and income attributable to the noncontrolling interests of TLP. On April 1, 2016, we sold all of the TLP common units we owned toArcLight. See Note 2 for a discussion of the sale.

XML

Significant Accounting Policies

6 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Significant Accounting Policies

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. We have included 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, 2016 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2016 included in our Annual Report on Form 10-K (“Annual Report”).

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment.The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction.We have restated our previously issued condensed consolidated statements of operations and condensed consolidated statements of comprehensive loss for the three months andsix months endedSeptember 30, 2015 and condensed consolidated statement of cash flows for the six months endedSeptember 30, 2015. See Note 17in our Annual Reportfor a summary of the impact of the error correction for the three months andsix months endedSeptember 30, 2015.

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, 2017.

Use of Estimates

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

Critical estimates we make in the preparation of our condensed consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations, the 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 various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Significant Accounting Policies

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

Fair Value Measurements

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

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

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

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

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our 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 non-cash mark-to-market adjustments) are reported within cost of sales in our 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 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.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues during the three months endedSeptember 30, 2016 and 2015 include $1.2 million and $1.5 million, respectively, and revenues during the six months endedSeptember 30, 2016 and 2015 include $2.5 million and $2.9 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

Supplemental Cash Flow Information

Non-cash investing and financing activities and supplemental disclosures of cash flow information are as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Value of common units issued in business combinations	$	3,969	$	—	$	3,969	$	11,367
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash interest paid	$	29,711	$	26,323	$	58,869	$	57,495
Income taxes paid (net of income tax refunds)	71		533		1,755		4,616

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

Inventories

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

Inventories consist of the following at the dates indicated:

	September 30, 2016		March 31, 2016
	(in thousands)
Crude oil	$	86,495	$	84,030
Natural gas liquids:
Propane	73,704		28,639
Butane	44,929		8,461
Other	5,936		6,011
Refined products:
Gasoline	126,821		80,569
Diesel	138,245		99,398
Renewables	34,328		52,458
Other	9,882		8,240
Total	$	520,340	$	367,806

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are 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 condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our condensed consolidated statements of cash flows.

On April 1, 2016, we sold all of the TLP common units we owned toArcLightfor approximately$112.4 millionin cash and recorded a gain on disposal of$104.1 millionduring thesix months endedSeptember 30, 2016.

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

Entity	Segment	Ownership Interest	Date Acquired or Formed	September 30, 2016		March 31, 2016
				(in thousands)
Glass Mountain (1)	Crude Oil Logistics	50%	December 2013	$	174,364	$	179,594
Ethanol production facility	Refined Products and Renewables	19%	December 2013	13,507		12,570
Water treatment and disposal facility	Water Solutions	50%	August 2015	2,235		2,238
Retail propane company	Retail Propane	50%	April 2015	556		972
TLP (2)	Refined Products and Renewables	0%	July 2014	—		8,301
Water supply company (3)	Water Solutions	100%	June 2014	—		15,875
Total				$	190,662	$	219,550

(1) When we acquired Gavilon, LLC, (“Gavilon Energy”), we recorded the investment in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $73.6 million at September 30, 2016. This difference relates primarily to goodwill and customer relationships.

(2) On April 1, 2016, we sold all of the TLP common units we owned.

(3) On June 3, 2016, we acquired the remaining65%ownership interest inthe water supply company, and as a result, the water supply company is now consolidated in our condensed consolidated financial statements (see Note 4).

Other Noncurrent Assets

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

	September 30, 2016		March 31, 2016
	(in thousands)
Loan receivable (1)	$	44,957	$	49,827
Tank bottoms (2)	42,044		42,044
Line fill (3)	35,013		35,060
Other	95,725		49,108
Total	$	217,739	$	176,039

(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) 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 September 30, 2016 and March 31, 2016, 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).

(3) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2016 and March 31, 2016, line fill consisted of 486,473 barrels and 487,104 barrels of crude oil, respectively.

Accrued Expenses and Other Payables

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

	September 30, 2016		March 31, 2016
	(in thousands)
Accrued compensation and benefits	$	19,322	$	40,517
Excise and other tax liabilities	56,147		59,455
Derivative liabilities	31,959		28,612
Accrued interest	19,594		20,543
Product exchange liabilities	7,045		5,843
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	20,454		29,343
Total	$	184,634	$	214,426

Sale of General Partner Interest in TLP

As previously reported, on February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight and 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 and six months endedSeptember 30, 2016, we recognized $7.6 million and $15.1 million, respectively, of the deferred gain in our condensed consolidated statements of operations. Within our 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, $154.4 million, is recorded in other noncurrent liabilities.

Noncontrolling Interests

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

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 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.

Also, as discussed in Note 4, we made certain adjustments during the three months endedSeptember 30, 2016 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the fiscal year ended March 31, 2016.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, “Simplifying the Accounting Adjustments for Measurement-Period Adjustments.” The ASU requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for the Partnership beginning April 1, 2016, and required a prospective method of adoption.

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.

Recent Accounting Pronouncements

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

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires a prospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our consolidated financial position or results of operations.

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 determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

XML

Income (Loss) Per Common Unit

6 Months Ended

Sep. 30, 2016

Earnings Per Unit [Abstract]

Income (Loss) Per Common Unit

Income (Loss) Per Common Unit

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

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except unit and per unit amounts)
Net (loss) income	$	(66,658	)	$	(6,100	)	$	116,095		$	(31,107	)
Less: Net loss (income) attributable to noncontrolling interests	59			(3,497		)	(5,774		)	(7,847		)
Net (loss) income attributable to NGL Energy Partners LP	(66,599		)	(9,597		)	110,321			(38,954		)
Less: Distributions to preferred unitholders	(8,668		)	—			(12,052		)	—
Less: Net loss (income) allocated to general partner (1)	45			(16,185		)	(158		)	(31,559		)
Net (loss) income allocated to common unitholders	$	(75,222	)	$	(25,782	)	$	98,111		$	(70,513	)
Basic (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.93		$	(0.67	)
Diluted (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.91		$	(0.67	)
Basic weighted average common units outstanding	106,186,389			105,189,463			105,183,556			104,542,427
Diluted weighted average common units outstanding	106,186,389			105,189,463			107,997,549			104,542,427

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

The diluted weighted average common units outstanding for the six months ended September 30, 2016 included 2,803,436 warrants and 10,621 performance units that were considered dilutive for the period. For the six months endedSeptember 30, 2016 and 2015, the restricted units were considered antidilutive. For the six months ended September 30, 2016, the convertible preferred units were considered antidilutive.

XML

Acquisitions

6 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Acquisitions

Acquisitions

Fiscal Year Ending March 31, 2017

Water Solutions Facilities

During the six months endedSeptember 30, 2016, we acquiredthreewater solutions facilities and paid $26.9 million of cash. In addition, we have recorded contingent consideration liabilities within accrued expenses and other payables and other noncurrent liabilities related to future royalty payments due to the sellers of one of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and percentage of oil revenues, multiplied by the expected disposal volumes and oil revenue for the expected useful life of the facility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of the uncertainty associated with the expected disposal volumes and oil revenue. As of the acquisition date, we recorded a contingent liability of $2.6 million. Also, for one of these facilities, we have recorded a liability for contingent royalty payments. We estimated the contingent royalty payments based on the contracted royalty rate, which is a flat rate per disposal barrel, multiplied by the expected disposal volumes for the expected useful life of the facility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of the uncertainty associated with the expected disposal volumes. As of the acquisition date, we recorded a contingent royalty liability of $8.2 million.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these water solutions facilities, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Property, plant and equipment	$	15,021
Goodwill	18,933
Intangible assets	3,878
Current liabilities	(1,239		)
Other noncurrent liabilities	(9,697		)
Fair value of net assets acquired	$	26,896

Goodwill represents a premium paid to expand the number of our disposal sites in an oilfield production basin currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in this oilfield production basin. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Acquisition of Remaining Interest in Water Solutions Facilities

On September 15, 2016, we acquired the remaining25%ownership interest inthreewater solutions facilities and paid $10.0 million of cash. 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 25% interest had a carrying value of $7.4 million.

Water Pipeline Company

As discussed below, on January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas. On June 3, 2016, we acquired an additional24.5%interest in this water pipeline company as part of the purchase and sale agreement discussed in Note 15. As we control this entity (and continue to retain our controlling financial interest), the acquisition of the additional 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 24.5% interest had a carrying value of $5.2 million.

Water Supply Company

On June 3, 2016, we acquired the remaining65%ownership interest ina water supply company (see Note 2). In exchange for this additional interest, we paid $1.0 million of cash and assumed an outstanding note payable, which relates to money this entity previously borrowed from us. Prior to the completion of this transaction, we accounted for our previously held35% ownership interest of this water supply company using the equity method of accounting (see Note 2). As we now own a controlling interest in this entity, we revalued our previously held35%ownership interest to fair value of $0.8 millionand recorded a loss of$14.9 million, which is recorded within revaluation of investments in our condensed consolidated statement of operations. 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 gain on bargain purchase of$0.6 million within revaluation of investments in our condensed consolidated statement of operations.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	1,713
Property, plant and equipment	8,874
Intangible asset	14,472
Current liabilities	(2,765		)
Notes payable-intercompany	(19,900		)
Fair value of net assets acquired	$	2,394

Retail Propane Businesses

During the six months endedSeptember 30, 2016, we acquired threeretail propane businesses and paid $72.1 million of cash and issued 218,617 common units, valued at $4.0 million, in exchange for these assets and operations. In connection with the issuance of the common units, we issued 219 general partner units to our general partner and less than $0.1 million in order to maintain its 0.1% general partner interest in us. The agreement for these acquisitions contemplate post-closing payments for certain working capital items.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at September 30, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2017. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	6,282
Property, plant and equipment	30,576
Goodwill	9,419
Intangible assets	36,950
Current liabilities	(5,555		)
Other noncurrent liabilities	(1,587		)
Fair value of net assets acquired	$	76,085

Fiscal Year Ended March 31, 2016

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 value of the assets acquired and liabilities assumed in a business combination.

Water Pipeline Company

During the six months endedSeptember 30, 2016, we finalized the purchase price accounting for the 57.125% interest acquired in a water pipeline company on January 7, 2016. During the three months ended June 30, 2016, we recorded an adjustment to reclassify approximately $1.1 million from property, plant and equipment to intangible assets, in order to present the fair value of the acquired rights-of-way as an indefinite-lived asset, which is consistent with our historical accounting policies. During the six months endedSeptember 30, 2016, we recorded an adjustment of $0.3 million to other noncurrent liabilities to recognize an asset retirement obligation related to assets that we acquired. This adjustment also increased goodwill by the same amount. There have been no other adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

Delaware BasinWater Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for the four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas we acquired on August 24, 2015. There have been no adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

Water Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for nine water facilities acquired under the development agreement during the fiscal year ended March 31, 2016. During the three months ended June 30, 2016, we received additional information and recorded an adjustment of $0.7 million to property, plant and equipment to recognize the fair value of additional assets that we acquired. This adjustment also reduced goodwill by the same amount. In addition, we paid $1.0 million in cash to the seller during the three months ended June 30, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

Retail PropaneBusinesses

During the six months endedSeptember 30, 2016, we finalized the purchase price accounting for five retail propane businesses we acquired during the fiscal year ended March 31, 2016 and paid $0.3 million in cash to a seller during the six months endedSeptember 30, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

XML

Property, Plant and Equipment

6 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

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

Description	Estimated Useful Lives	September 30, 2016			March 31, 2016
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	168,754		$	169,758
Refined products terminal assets and equipment	20 years	6,844			6,844
Retail propane equipment	2–30 years	227,442			201,312
Vehicles and railcars	3–25 years	194,291			185,547
Water treatment facilities and equipment	3–30 years	535,255			508,239
Crude oil tanks and related equipment	2–40 years	140,245			137,894
Barges and towboats	5–40 years	89,973			86,731
Information technology equipment	3–7 years	42,218			38,653
Buildings and leasehold improvements	3–40 years	123,005			118,885
Land		50,132			47,114
Tank bottoms		20,105			20,355
Other	3–30 years	56,450			11,699
Construction in progress		425,066			383,032
		2,079,780			1,916,063
Accumulated depreciation		(324,364		)	(266,491		)
Net property, plant and equipment		$	1,755,416		$	1,649,572

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Depreciation expense	$	28,703	$	34,469	$	56,357	$	70,264
Capitalized interest expense	1,069		549		4,804		690

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

	September 30, 2016			March 31, 2016
Product	Volume (in barrels) (in thousands)	Value (in thousands)		Volume (in barrels) (in thousands)	Value (in thousands)
Crude oil	229	$	19,120	231	$	19,348
Other	24	985		24	1,007
Total		$	20,105		$	20,355

Loss on Disposal of Assets

During the three months and six months endedSeptember 30, 2016, we recorded losses of $8.5 million and $10.8 million, respectively, due primarily to the sales and write-down of certain assets in our Crude Oil Logistics and Water Solutions segments. During the three months and six months endedSeptember 30, 2015, we recorded losses of $1.1 million and $1.7 million, respectively, primarily due to the sales of certain assets in our Crude Oil Logistics and Water Solutions segments. These losses are reported within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statements of operations.

XML

Goodwill

6 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The following table summarizes changes in goodwill by segment during the six months endedSeptember 30, 2016:

	Crude Oil Logistics		Water Solutions			Liquids		Retail Propane			Refined Products and Renewables		Total
	(in thousands)
Balances at March 31, 2016	$	579,846	$	290,915		$	266,046	$	127,428		$	51,127	$	1,315,362
Revisions to acquisition accounting (Note 4)	—		(419		)	—		(2		)	—		(421		)
Acquisitions (Note 4)	—		18,933			—		9,419			—		28,352
Adjustment to initial impairment estimate	—		124,662			—		—			—		124,662
Balances at September 30, 2016	$	579,846	$	434,091		$	266,046	$	136,845		$	51,127	$	1,467,955

Goodwill Adjustment to Initial Impairment Estimate

During the three months ended March 31, 2016, we recorded a preliminary goodwill impairment charge of $380.2 million. During the three months ended June 30, 2016, we finalized our goodwill impairment analysis, with the assistance of a third party valuation firm. As a result of finalizing our analysis, we determined that we needed to reverse $124.7 million of the previously recorded goodwill impairment recorded during the three months ended March 31, 2016. The reversal was due primarily to the change in the fair value of our customer relationship intangible assets. With the assistance of the third party valuation firm, inputs such as revenue growth rates and attrition rates related to existing customers were refined and resulted in a lower fair value allocated to customer relationships than in our preliminary calculation. We recorded the reversal within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations.

XML

Intangible Assets

6 Months Ended

Sep. 30, 2016

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Intangible Assets

Intangible Assets

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

		September 30, 2016						March 31, 2016
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	883,896	$	274,111	$	609,785	$	852,118	$	233,838	$	618,280
Pipeline capacity rights	30 years	161,589		8,957		152,632		119,636		6,559		113,077
Water facility development agreement	5 years	—		—		—		14,000		7,700		6,300
Executory contracts and other agreements	2–30 years	22,713		19,699		3,014		23,920		21,075		2,845
Non-compete agreements	2–32 years	31,784		15,101		16,683		20,903		13,564		7,339
Trade names	1–10 years	15,439		12,882		2,557		15,439		12,034		3,405
Debt issuance costs (1)	3 years	39,977		25,564		14,413		39,942		22,108		17,834
Total amortizable		1,155,398		356,314		799,084		1,085,958		316,878		769,080
Non-amortizable:
Customer commitments		310,000		—		310,000		310,000		—		310,000
Rights-of-way and easements		47,721		—		47,721		47,190		—		47,190
Water rights		14,472		—		14,472		—		—		—
Trade names		18,870		—		18,870		22,620		—		22,620
Total non-amortizable		391,063		—		391,063		379,810		—		379,810
Total		$	1,546,461	$	356,314	$	1,190,147	$	1,465,768	$	316,878	$	1,148,890

(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.

The weighted-average remaining amortization period for intangible assets is approximately 8.6 years.

Write off of Intangible Assets

As a result of terminating the development agreement in the Water Solutions segment (see Note 15), we incurred a loss of $5.8 million to write off the water facility development agreement. During thesix months endedSeptember 30, 2016, we wrote-off$5.2 millionrelated to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis (see Note 6). These losses are reported within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations.

Amortization expense is as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
Recorded In	2016		2015		2016		2015
	(in thousands)
Depreciation and amortization	$	21,900	$	22,291	$	43,152	$	46,328
Cost of sales	1,749		1,700		3,345		3,401
Interest expense	1,731		1,470		3,456		2,954
Total	$	25,380	$	25,461	$	49,953	$	52,683

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

Year Ending March 31,
2017 (six months)	$	51,028
2018	98,717
2019	89,701
2020	82,185
2021	69,422
Thereafter	408,031
Total	$	799,084

XML

Long-Term Debt

6 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

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

	September 30, 2016							March 31, 2016
	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	$	1,312,000	$	—		$	1,312,000	$	1,229,500	$	—		$	1,229,500
Working capital borrowings	710,500		—			710,500		618,500		—			618,500
5.125% Notes due 2019	383,467		(3,871		)	379,596		388,467		(4,681		)	383,786
6.875% Notes due 2021	369,063		(6,433		)	362,630		388,289		(7,545		)	380,744
6.650% Notes due 2022	250,000		(3,055		)	246,945		250,000		(3,166		)	246,834
Other long-term debt	59,506		(123		)	59,383		61,488		(108		)	61,380
	3,084,536		(13,482		)	3,071,054		2,936,244		(15,500		)	2,920,744
Less: Current maturities	8,046		—			8,046		7,907		—			7,907
Long-term debt	$	3,076,490	$	(13,482	)	$	3,063,008	$	2,928,337	$	(15,500	)	$	2,912,837

(1) Debt issuance costs related to the Revolving Credit Facility (as defined herein) 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 our notes due in 2019, 2021 and 2022 and other long-term debt was $1.0 million and $0.8 million during the three months endedSeptember 30, 2016 and 2015, respectively, and $1.8 million and $1.6 million during the six months ended September 30, 2016 and 2015, respectively.

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

Year Ending March 31,
2017 (six months)	$	1,619
2018	3,229
2019	3,226
2020	2,236
2021	1,827
Thereafter	1,345
Total	$	13,482

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at September 30, 2016. At that date, we had outstanding borrowings of$1.312 billionon the Expansion Capital Facility.The Working Capital Facility had a total capacity of$1.038 billionfor cash borrowings and letters of credit atSeptember 30, 2016. At that date, we had outstanding borrowings of$710.5 millionand outstanding letters of credit of $75.3 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50%to1.75%per year or (ii) an adjusted LIBOR rate plus a margin of1.50%to2.75% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At September 30, 2016, the borrowings under the Credit Agreement had an average interest rateof2.83%, calculated as the LIBOR rate of0.53%plus a margin of2.25%for LIBOR borrowings and the prime rate of3.50%plus a margin of1.25%on alternate base rate borrowings.AtSeptember 30, 2016, the interest rate in effect on letters of credit was2.25%. Commitment fees are charged at a rate ranging from0.38%to0.50% on any unused capacity.

The Revolving Credit Facility is secured by substantially all of our assets. The Credit Agreement also specifies that our leverage ratio cannot be more than4.75to1 and that our interest coverage ratio cannot be less than2.75to1at any quarter end.AtSeptember 30, 2016, our leverage ratio was approximately4.15to1and our interest coverage ratio was approximately4.60to1.

At September 30, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued$400.0 millionof5.125% Senior Notes Due 2019 (the “2019 Notes”). During thethree months ended June 30, 2016, we repurchased$5.0 millionof our 2019 Notes for an aggregate purchase price of$3.1 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of$1.8 million(net of the write off of debt issuance costs of$0.1 million).

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued$450.0 millionof6.875%Senior Notes Due 2021 (the “2021 Notes”). During thethree months ended June 30, 2016,we repurchased$19.2 millionof our 2021 Notes for an aggregate purchase price of$12.0 million(excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of$6.8 million(net of the write off of debt issuance costs of$0.4 million).

The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

AtSeptember 30, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued$250.0 millionof Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of$25.0 millionbeginning on December 19, 2017 and ending on the maturity date of June 19, 2022.We have the option to prepay outstanding principal, although we would incur a prepayment penalty.On September 30, 2016, we amended our Note Purchase Agreement which, among other things, changes the maximum allowable leverage ratio to match the maximum allowable leverage ratio and the calculation of such ratio under our Credit Agreement. Additionally, the amendment provides for an increase in interest charged should our leverage ratio exceed certain predetermined levels. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

AtSeptember 30, 2016, we were in compliance with the covenants under the Note Purchase Agreement.

Other Long-Term Debt

We have certain notes payable related to equipment financing. We have also executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. These instruments have a combined principal balance of $59.5 million at September 30, 2016, and the interest rates on these instruments range from 1.17% to 7.08% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at September 30, 2016:

Year Ending March 31,	Revolving Credit Facility		2019 Notes		2021 Notes		2022 Notes		Other Long-Term Debt		Total
	(in thousands)
2017 (six months)	$	—	$	—	$	—	$	—	$	3,405	$	3,405
2018	—		—		—		25,000		8,014		33,014
2019	2,022,500		—		—		50,000		6,857		2,079,357
2020	—		383,467		—		50,000		6,372		439,839
2021	—		—		—		50,000		34,728		84,728
Thereafter	—		—		369,063		75,000		130		444,193
Total	$	2,022,500	$	383,467	$	369,063	$	250,000	$	59,506	$	3,084,536

XML

Income Taxes

6 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

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. Our fiscal years 2013 to 2016 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our condensed consolidated financial statements at September 30, 2016 or March 31, 2016.

XML

Commitments and Contingencies

6 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 condensed consolidated balance sheet at September 30, 2016 includes a liability, measured on an undiscounted basis, of $2.2 million related to environmental matters, which is reported within accrued expenses and other payables. Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (hereafter referred to as “Gavilon”) of alleged violations in 2011 by Gavilon of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by NGL 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 and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint relates to transactions between Gavilon and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon in 2011. The complaint seeks an order declaring that the RINs generated by Western Dubuque be declared invalid, that the defendants retire and replace such RINs and that the defendants pay statutory civil penalties. Consistent with our position against the previous EPA allegations, we deny the allegations in this civil complaint and intend to vigorously defend ourselves in the civil action. However, at this time NGL is 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 is a rollforward of our asset retirement obligation, which is reported within other noncurrent liabilities in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2016	$	5,574
Liabilities assumed in acquisitions	406
Accretion expense	207
Balance at September 30, 2016	$	6,187

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

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	67,837
2018	122,935
2019	101,047
2020	90,112
2021	80,457
Thereafter	135,486
Total	$	597,874

Rental expense relating to operating leases was $27.0 million and $33.3 million during the three months endedSeptember 30, 2016 and 2015, respectively, and $56.9 million and $67.1 million during the six months ended September 30, 2016 and 2015, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. The following table summarizes future minimum throughput payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	26,008
2018	52,082
2019	52,170
2020	42,418
Total	$	172,678

Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods. The following table summarizes such commitments at September 30, 2016:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	35,592	$	18,710
Natural gas liquids index-price (gallons)	587,044	347,020
Crude oil fixed-price (barrels)	1,993	88,079
Crude oil index-price (barrels)	14,466	655,273
Sale commitments:
Natural gas liquids fixed-price (gallons)	163,546	105,868
Natural gas liquids index-price (gallons)	414,042	317,983
Crude oil fixed-price (barrels)	3,415	152,584
Crude oil index-price (barrels)	12,953	637,731

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (as discussed in Note 12) or inventory positions (as discussed 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 condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $41.0 million of our prepaid expenses and other current assets and $29.6 million of our accrued expenses and other payables at September 30, 2016.

XML

Equity

6 Months Ended

Sep. 30, 2016

Equity [Abstract]

Equity

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.

Our Distributions

The following table summarizes distributions declared for the last three 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 21, 2016	May 3, 2016	May 13, 2016	$	0.3900	$	40,626	$	70
July 22, 2016	August 4, 2016	August 12, 2016	0.3900		41,146		71
October 20, 2016	November 4, 2016	November 14, 2016	0.3900		41,907		72

Class A Convertible Preferred Units

On April 21, 2016, we entered into a private placement agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. and its co-investors (“Oaktree”). On June 23, 2016, the private placement agreement was amended to increase the aggregate principal amount from $200 million to $240 million. On May 11, 2016, we received an initial $100 million (“initial closing date”) and Oaktree received 8,309,237 Preferred Units, and on June 24, 2016, we received the remaining $140 million (“second closing date”) and Oaktree received 11,632,932 Preferred Units. In addition, Oaktree received 4,375,112 warrants (1,822,963 at the initial closing date and 2,552,149 at the second closing date) to purchase common units at an exercise price of $0.01 per common unit.

We will pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Preferred Units then outstanding in cash, to the extent declared by the board of directors of our general partner. To the extent declared, such distributions will be paid for each such quarter within 45 days after each quarter end. On July 22, 2016, we declared a pro rata distribution for the three months ended June 30, 2016 of $1.8 million which was paid to the holders of the Preferred Units on August 12, 2016. On October 20, 2016, we declared a distribution for the three months ended September 30, 2016 of $6.4 million to be paid to the holders of the Preferred Units on November 14, 2016.

If the Preferred Unit quarterly distribution is not made in full in cash for any quarter, the Preferred Unit distribution rate will increase by one quarter of a percentage point (0.25%) per annum beginning with distributions for the first six-month period that a payment default is in effect, and will further increase by an additional one quarter of a percentage point (0.25%) beginning with distributions for the next six-month period during which a payment default remains in effect. The deficiency rate shall not exceed 11.25% per annum; as long as the default is occurring, the amount of accrued but unpaid Preferred Unit quarterly distributions shall increase at an annual rate of 10.75%, compounded quarterly, until paid in full.

The Preferred Units have no mandatory redemption date but are redeemable, at our election, any time after the first anniversary of the closing date. We have the right to redeem all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the redemption multiple then in effect. The redemption multiple means (a) 140% for redemptions occurring on or after the first, but prior to the second anniversary of the closing date, (b) 115% for the redemptions occurring on or after the second, but prior to the third anniversary of the closing date, (c) 110% for redemptions occurring on or after the third, but prior to the eighth anniversary of the closing date and (d) 101% for redemptions occurring on or after the eighth anniversary of the closing date.

At any time after the third anniversary of the initial closing date, the Preferred Unit holders shall have the right to convert all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the conversion multiple then in effect, which may be settled in common units, cash or a combination, at our discretion. The conversion multiple means if our common units are trading at or above $12.035 (“the initial conversion price”), the conversion price is not adjusted. However, if the conversion price is less than the initial conversion price, the conversion price will be reset to the greater of (i) the adjusted volume weighted average price of our common units for the fifteen trading days immediately preceding the third anniversary of the closing date or (ii) $5.00.

Upon a change of control of the Partnership, each Preferred Unit holder shall have the right, at its election, to either (i) elect to have its Preferred Units converted to common units; (ii) if we are the surviving entity of such change of control, it can elect to continue to hold its Preferred Units; or (iii) require us to redeem its Preferred Units for cash equal to (a) prior to the first anniversary of the closing date, 140% of the unit purchase price; (b) on or after the first but prior to the second anniversary of the closing date, 130% of the unit purchase price; (c) on or after the second anniversary of the closing date, 120% of the unit purchase price; and (d) thereafter, 101% of the unit purchase price. In each case, this amount will include any accrued but unpaid distributions at the redemption date.

Under the private placement agreement, we are required to file within 180 days of the initial closing date a registration statement registering the resales of common units issued or to be issued upon conversion of the Preferred Units or exercise of the warrants and have the registration statement declared effective within 360 days after the closing date. We are required to continue to maintain the effectiveness of the registration statement until all securities have been sold. If the registration statement is not effective before the deadline, then the Preferred Unit holders shall be entitled to liquidated damages. The liquidated damages, which would accrue daily, are an amount equal to 0.25% of the multiplier for the first 60 day period following the effectiveness deadline plus an additional 0.25% of the multiplier for each subsequent 30 day period (i.e. 0.50% for 61-90 days, 0.75% for 91-120 days and 1.00% thereafter) up to a maximum of 1.00% of the liquidated damage multiplier per 30 day period, until the registration statement becomes effective or the Preferred Units are sold.

The warrants have an eight year term, after which unexercised warrants will expire. 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 of the original issue date and the final one-third may be converted from and after the third anniversary. Upon a change of control or in the event we exercise our redemption right with respect to the Preferred Units, all unvested warrants shall immediately vest and be exercisable in full.

We received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of Preferred Units and warrants. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units ($186.4 million), which includes the value of the beneficial conversion feature, and warrants ($48.6 million). As discussed below, $131.5 million of the amount allocated to the Preferred Units is allocated to the intrinsic value of a beneficial conversion feature. A beneficial conversion feature is defined as a nondetachable conversion feature that is in the money at the commitment date. Per the applicable accounting guidance, we are required to allocate a portion of the proceeds allocated to the Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per share value of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We record the accretion attributed to the beneficial conversion feature as a deemed distribution using the effective interest method over the three year period prior to the effective dates of the holders’ conversion right. Accretion for the beneficial conversion feature was $2.2 million for the three months endedSeptember 30, 2016 and $3.8 million for the six months ended September 30, 2016.

As discussed above, the Preferred Units are not mandatorily redeemable but are redeemable upon a change of control, which was not certain to occur at the issuance of the Preferred Units. Due to the redemption being conditioned upon an event that is not certain to occur or that is not under our control, we are required to record the value allocated to the Preferred Units, excluding the value of the beneficial conversion feature, between liabilities and equity (mezzanine or temporary equity) within our condensed consolidated balance sheet. The value allocated to the warrants and the beneficial conversion feature were recorded as part of Limited Partners’ equity within our condensed consolidated balance sheet.

Amended and Restated Partnership Agreement

On June 24, 2016, NGL Energy Holdings LLC executed the Third Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Preferred Units are defined in the amended and restated partnership agreement. The 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. The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless redeemed by the Partnership or converted into common units at the election of the Partnership or the Preferred Unit holders or in connection with a change of control.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with anat-the-market program (the “ATM Program”)pursuant to which we may issue and sell common units for up to$200.0 millionin gross proceeds.This ATM Program is registered with the SEC on an effective registration statement on Form S-3.During thethree months endedSeptember 30, 2016, we sold524,000common units for proceeds of$9.6 million, net of offering costs ofless than $0.1 million. In connection with the issuance of the common units, we issued524general partner units to our general partner andless than $0.1 millionin order to maintain its0.1%general partner interest in us. As of September 30, 2016, approximately $190.4 million remained available for sale under the Partnership’s ATM Program.

Subsequent to September 30, 2016, we sold an additional192,000common units for proceeds of$3.7 million, net of offering costs ofless than $0.1 million.

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 in the event of a change in 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 awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

During the three months ended September 30, 2016, we changed our process for how taxes are withheld upon the vesting of restricted units. Previously, employees could choose to pay cash for their portion of the taxes or have us withhold enough units to meet their tax withholding requirements. Employees could also elect to have the units withheld to exceed the statutory minimums. Now, employees will still be able to pay cash to satisfy their tax obligation or they can elect to sell enough units, through a broker assisted cashless exercise program, to meet their tax obligation. As a result of this change in process, the unvested restricted units and future grants are eligible for equity classification. Prior to this change in process, we classified any Service Awards or Performance Awards granted as liabilities and were required to recalculate the fair value of the award at each reporting date. Awards classified as equity are valued only at their grant date and are not revalued at each reporting date. As of June 30, 2016, we had liabilities related to our Service Awards and Performance Awards of $25.6 million and $1.8 million, respectively, which we reclassified to equity.

The following table summarizes the Service Award activity during the six months endedSeptember 30, 2016:

Unvested Service Award units at March 31, 2016	2,297,132
Units granted	3,048,100
Units vested and issued	(2,340,082	)
Units forfeited	(322,100	)
Unvested Service Award units at September 30, 2016	2,683,050

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

Year Ending March 31,
2017 (six months)	10,000
2018	887,350
2019	894,800
Thereafter	890,900
Unvested Service Award units at September 30, 2016	2,683,050

Service Awards are valued at the market price as of the date of grant 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 must at least equal the portion of the grant-date value of the award that is vested at that date. During the three months endedSeptember 30, 2016 and 2015, we recorded compensation expense related to Service Award units of $25.8 million and $14.9 million, respectively. During the six months endedSeptember 30, 2016 and 2015, we recorded compensation expense related to Service Award units of $46.7 million and $33.4 million, respectively.

Of the restricted units granted and vested during the six months endedSeptember 30, 2016, 1,008,091 units were granted as a bonus for performance during the fiscal year ended March 31, 2016. We accrued expense of $16.8 million during the fiscal year ended March 31, 2016 as an estimate of the value of such bonus units that would be granted. During the six months endedSeptember 30, 2016, we recorded an additional $2.2 million to true up the estimate to the $19.0 million of actual expense associated with these bonuses. Since the units were not formally granted until August 2016, the full $19.0 million is reflected in the expense during the three months and six months ended September 30, 2016 in the amounts in the preceding paragraph above.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	9,329
2018	12,239
2019	8,853
Thereafter	2,317
Total	$	32,738

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 September 30, 2016, 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

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

Our Relative Total Unitholder Return Percentile Ranking	Payout (% of Target Units)
Less than 50th percentile	0%
Between the 50th and 75th percentile	50%–100%
Between the 75th and 90th percentile	100%–200%
Above the 90% percentile	200%

The following table summarizes the Performance Award activity during the six months ended September 30, 2016:

Unvested Performance Award units at March 31, 2016	637,382
Units granted	932,309
Units forfeited	(380,691	)
Unvested Performance Award units at September 30, 2016	1,189,000

During the July 1, 2013 through June 30, 2016 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 units vested on July 1, 2016 and are considered to be forfeited.

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. During the three months ended September 30, 2016 and 2015, we recorded compensation expense related to Performance Award units of $1.6 million and $0.3 million, respectively. During the six months ended September 30, 2016 and 2015, we recorded compensation expense related to Performance Award units of $3.1 million and $18.1 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	4,138
2018	6,197
2019	3,232
Thereafter	655
Total	$	14,222

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the LTIP plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2016, approximately 1.1 million common units remain available for issuance under the LTIP.

XML

Fair Value of Financial Instruments

6 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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

Commodity Derivatives

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

	September 30, 2016						March 31, 2016
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	2,512		$	(40,260	)	$	47,361		$	(3,983	)
Level 2 measurements	42,455			(32,253		)	32,700			(28,612		)
	44,967			(72,513		)	80,061			(32,595		)
Netting of counterparty contracts (1)	(3,091		)	3,091			(3,384		)	3,384
Net cash collateral provided (held)	21			37,463			(18,176		)	599
Commodity derivatives in condensed consolidated balance sheet	$	41,897		$	(31,959	)	$	58,501		$	(28,612	)

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

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

	September 30, 2016			March 31, 2016
	(in thousands)
Prepaid expenses and other current assets	$	41,897		$	58,501
Accrued expenses and other payables	(31,959		)	(28,612		)
Net commodity derivative asset	$	9,938		$	29,889

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 September 30, 2016:
Cross-commodity (1)	October 2016–March 2017	126		$	1,465
Crude oil fixed-price (2)	October 2016–December 2016	(588	)	(3,041		)
Propane fixed-price (2)	October 2016–December 2017	462		518
Refined products fixed-price (2)	October 2016–September 2017	(5,628	)	(22,607		)
Other	October 2016–March 2022			(3,881		)
				(27,546		)
Net cash collateral provided				37,484
Net commodity derivative asset in condensed consolidated balance sheet				$	9,938
At March 31, 2016:
Cross-commodity (1)	April 2016–March 2017	251		$	1,663
Crude oil fixed-price (2)	April 2016–December 2016	(1,583	)	(3,655		)
Propane fixed-price (2)	April 2016–December 2017	540		(592		)
Refined products fixed-price (2)	April 2016–June 2017	(5,355	)	48,557
Other	April 2016–March 2017			1,493
				47,466
Net cash collateral held				(17,577		)
Net commodity derivative asset in condensed consolidated balance sheet				$	29,889

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

(2) 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 and six months endedSeptember 30, 2016, we recorded a net gain of $14.7 million and a net loss of $45.0 million, respectively, and during the three months and six months endedSeptember 30, 2015, we recorded net gains of $85.8 million and $44.5 million, respectively, from our commodity derivatives to cost of sales.

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. AtSeptember 30, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates.AtSeptember 30, 2016, we had$2.0 billionof outstanding borrowings under our Revolving Credit Facility at an average interest rate of2.83%.

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2016 (in thousands):

2019 Notes	$	360,459
2021 Notes	349,995
2022 Notes	253,838

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by 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.

XML

Segments

6 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segments

Segments

The following table summarizes certain financial data related to our segments for the periods indicated. 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.

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	341,981		$	997,106		$	756,600		$	2,309,889
Crude oil transportation and other	9,172			12,746			22,106			31,695
Elimination of intersegment sales	(1,268		)	(2,274		)	(2,870		)	(6,222		)
Total Crude Oil Logistics revenues	349,885			1,007,578			775,836			2,335,362
Water Solutions:
Service fees	28,528			35,203			54,225			71,941
Recovered hydrocarbons	5,681			10,746			12,877			26,564
Other revenues	5,524			1,545			8,384			3,282
Total Water Solutions revenues	39,733			47,494			75,486			101,787
Liquids:
Propane sales	101,613			98,770			198,084			204,260
Other product sales	135,700			160,836			249,435			308,347
Other revenues	8,075			10,122			15,222			19,622
Elimination of intersegment sales	(11,128		)	(10,736		)	(23,432		)	(24,252		)
Total Liquids revenues	234,260			258,992			439,309			507,977
Retail Propane:
Propane sales	36,170			36,119			77,811			79,304
Distillate sales	5,589			7,678			16,044			20,625
Other revenues	9,331			9,409			17,638			17,724
Elimination of intersegment sales	—			—			(16		)	—
Total Retail Propane revenues	51,090			53,206			111,477			117,653
Refined Products and Renewables:
Refined products sales	2,274,715			1,704,259			4,151,572			3,413,208
Renewables sales	95,830			93,189			202,312			199,342
Service fees	(121		)	28,739			11,145			56,812
Elimination of intersegment sales	(102		)	(262		)	(144		)	(477		)
Total Refined Products and Renewables revenues	2,370,322			1,825,925			4,364,885			3,668,885
Corporate and Other	248			—			515			—
Total revenues	$	3,045,538		$	3,193,195		$	5,767,508		$	6,731,664
Depreciation and Amortization:
Crude Oil Logistics	$	9,025		$	10,053		$	17,993		$	20,055
Water Solutions	25,129			22,416			49,563			43,262
Liquids	4,425			2,745			8,874			7,749
Retail Propane	10,705			8,909			20,392			17,615
Refined Products and Renewables	416			11,152			833			25,327
Corporate and Other	903			1,486			1,854			2,584
Total depreciation and amortization	$	50,603		$	56,761		$	99,509		$	116,592
Operating Income (Loss):
Crude Oil Logistics	$	(19,039	)	$	(75	)	$	(19,664	)	$	11,885
Water Solutions	(4,430		)	18,257			75,034			28,704
Liquids	8,384			20,370			8,327			19,899
Retail Propane	(8,717		)	(1,765		)	(11,219		)	(2,465		)
Refined Products and Renewables	11,387			(5,244		)	161,156			27,776
Corporate and Other	(23,413		)	(13,245		)	(55,562		)	(68,711		)
Total operating (loss) income	$	(35,828	)	$	18,298		$	158,072		$	17,088

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 September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Crude Oil Logistics	$	32,397	$	44,384	$	104,702	$	107,023
Water Solutions	25,237		72,531		68,353		133,020
Liquids	6,693		18,886		13,161		36,064
Retail Propane	71,425		15,814		77,974		22,709
Refined Products and Renewables	1,143		7,588		1,167		23,283
Corporate and Other	614		—		1,732		1,169
Total	$	137,509	$	159,203	$	267,089	$	323,268

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:

	September 30, 2016		March 31, 2016
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,720,278	$	1,679,027
Water Solutions	1,316,196		1,162,405
Liquids	575,963		572,081
Retail Propane	549,429		483,330
Refined Products and Renewables	219,157		180,783
Corporate and Other	32,495		36,198
Total	$	4,413,518	$	4,113,824
Total assets:
Crude Oil Logistics	$	2,318,083	$	2,197,113
Water Solutions	1,354,786		1,236,875
Liquids	785,303		693,872
Retail Propane	611,340		538,267
Refined Products and Renewables	904,386		765,806
Corporate and Other	100,020		128,222
Total	$	6,073,918	$	5,560,155

XML

Transactions with Affiliates

6 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Transactions with Affiliates

Transactions with Affiliates

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

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

Certain members of our management and members of their families 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 six months endedSeptember 30, 2016, $10.5 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Sales to SemGroup	$	3,513	$	4,593	$	3,584	$	42,031
Purchases from SemGroup	1,938		6,478		3,963		45,303
Sales to equity method investees	95		1,696		500		3,086
Purchases from equity method investees	27,345		24,816		57,992		55,764
Sales to entities affiliated with management	75		91		152		198
Purchases from entities affiliated with management	3,493		16,214		11,736		23,394

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

	September 30, 2016		March 31, 2016
	(in thousands)
Receivables from SemGroup	$	3,401	$	1,166
Receivables from equity method investees	—		14,446
Receivables from entities affiliated with management	139		13
Total	$	3,540	$	15,625

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

	September 30, 2016		March 31, 2016
	(in thousands)
Payables to SemGroup	$	4,015	$	1,823
Payables to equity method investees	1,155		3,947
Payables to entities affiliated with management	1,074		1,423
Total	$	6,244	$	7,193

We also have a loan receivable of $1.7 million at September 30, 2016 from an equity method investee 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.

We had a loan receivable of $22.3 million at March 31, 2016 from an equity method investee. During the three months ended June 30, 2016, we received loan payments of $0.7 million from our investee in accordance with the loan agreement. During thethree months ended June 30, 2016, we recorded an impairment of$1.7 millionrelated to this loan receivable. On June 3, 2016, we acquired the remaining65%ownership interest in this equity method investee (see Note 4) and this loan receivable is now eliminated upon consolidation.

XML

Other Matters

6 Months Ended

Sep. 30, 2016

Other Matters [Abstract]

Other Matters

Other Matters

Purchase of Pipeline Capacity Allocations

On certain interstate refined product pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historical shipment volumes. During the six months endedSeptember 30, 2016, we paid $42.0 millionto acquire certain refined product pipeline capacity allocations from other shippers on the Colonial pipeline.

Termination of Development Agreement

On June 3, 2016, we entered into a purchase and sale agreement with the counterparty to the development agreement in our Water Solutions segment (as discussed in Note 4). Total cash consideration paid under the agreement was $49.6 million, of which $2.1 million was withheld and recorded in accrued expenses and other payables as of June 30, 2016, and in return we received the following:

• Termination of the development agreement (see Note 4);

• Additional interest in the water pipeline company we acquired in January 2016 (see Note 4);

• Release of contingent consideration liabilities (see Note 4) attributed to certain of our water treatment and disposal facilities;

• Certain parcels of land and permits to develop saltwater disposal wells and other parcels of land containing water wells and equipment; and

• A two-year non-compete agreement with the counterparty.

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 shall be allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and shall not give rise to goodwill or bargain purchase gains. We allocated $1.2 million of the total consideration to property, plant and equipment, $3.3 million to intangible assets, $2.8 million to noncontrolling interest, $25.5 million to the release of contingent consideration liabilities and $16.9 million to the termination of the development agreement. We recorded a $21.3 million gain on the release of $46.8 million of contingent consideration liabilities, which was recorded within gain on early extinguishment of liabilities in our condensed consolidated statement of operations during the six months endedSeptember 30, 2016. For the termination of the development agreement, we recorded a loss of $22.7 million, which included the carrying value of the development agreement asset that was written off (seeNote 7). This loss was recorded within loss (gain) on disposal or impairment of assets, net in our condensed consolidated statement of operations during the six months endedSeptember 30, 2016.

XML

Subsequent Events

6 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

2023 Notes

In October 2016, we issued$700.0 millionof Senior Unsecured Notes (the “2023 Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately$688.0 million, after the initial purchasers’ discount of$10.5 millionand estimated offering costs of$1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The 2023 Notes mature on November 1, 2023 and bear interest at a fixed rate of7.50%, payable on May 1 and November 1 of each year.

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information

6 Months Ended

Sep. 30, 2016

Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and 2021 Notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP (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 2019 Notes and 2021 Notes. Since NGL Energy Partners LP received the proceeds from the issuance of the 2019 Notes and 2021 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 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

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

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

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,116	$	—	$	12,179		$	1,132		$	—		$	23,427
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		585,720			6,354			—			592,074
Accounts receivable-affiliates	—		—		3,540			—			—			3,540
Inventories	—		—		519,795			545			—			520,340
Prepaid expenses and other current assets	—		—		109,969			949			—			110,918
Total current assets	10,116		—		1,231,203			8,980			—			1,250,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,653,011			102,405			—			1,755,416
GOODWILL	—		—		1,448,661			19,294			—			1,467,955
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,166,439			23,708			—			1,190,147
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		190,662			—			—			190,662
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,290,616		—		(1,279,908		)	(10,708		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,689,633		—		96,577			—			(1,786,210		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		1,700			—			—			1,700
OTHER NONCURRENT ASSETS	—		—		217,618			121			—			217,739
Total assets	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918
LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	510,535		$	1,569		$	—		$	512,104
Accounts payable-affiliates	1		—		6,054			189			—			6,244
Accrued expenses and other payables	16,232		—		164,918			3,484			—			184,634
Advance payments received from customers	—		—		87,094			731			—			87,825
Current maturities of long-term debt	—		—		7,252			794			—			8,046
Total current liabilities	16,233		—		775,853			6,767			—			798,853
LONG-TERM DEBT, net of debt issuance costs and current maturities	989,171		—		2,067,264			6,573			—			3,063,008
OTHER NONCURRENT LIABILITIES	—		—		193,213			4,788			—			198,001
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	58,742		—		—			—			—			58,742
EQUITY:
Partners’ equity	1,926,219		—		1,690,096			125,851			(1,815,305		)	1,926,861
Accumulated other comprehensive loss	—		—		(463		)	(179		)	—			(642		)
Noncontrolling interests	—		—		—			—			29,095			29,095
Total equity	1,926,219		—		1,689,633			125,672			(1,786,210		)	1,955,314
Total liabilities, convertible preferred units and equity	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	March 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,749	$	—	$	784		$	1,643		$	—		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		516,362			4,652			—			521,014
Accounts receivable-affiliates	—		—		15,625			—			—			15,625
Inventories	—		—		367,250			556			—			367,806
Prepaid expenses and other current assets	—		—		94,426			1,433			—			95,859
Total current assets	25,749		—		994,447			8,284			—			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,568,488			81,084			—			1,649,572
GOODWILL	—		—		1,313,364			1,998			—			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,146,355			2,535			—			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		219,550			—			—			219,550
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,404,479		—		(1,402,360		)	(2,119		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,254,383		—		42,227			—			(1,296,610		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		22,262			—			—			22,262
OTHER NONCURRENT ASSETS	—		—		175,512			527			—			176,039
Total assets	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	417,707		$	2,599		$	—		$	420,306
Accounts payable-affiliates	1		—		7,190			2			—			7,193
Accrued expenses and other payables	16,887		—		196,596			943			—			214,426
Advance payments received from customers	—		—		55,737			448			—			56,185
Current maturities of long-term debt	—		—		7,109			798			—			7,907
Total current liabilities	16,888		—		684,339			4,790			—			706,017
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,011,365		—		1,894,428			7,044			—			2,912,837
OTHER NONCURRENT LIABILITIES	—		—		246,695			541			—			247,236
EQUITY:
Partners’ equity	1,656,358		—		1,254,384			80,090			(1,334,317		)	1,656,515
Accumulated other comprehensive loss	—		—		(1		)	(156		)	—			(157		)
Noncontrolling interests	—		—		—			—			37,707			37,707
Total equity	1,656,358		—		1,254,383			79,934			(1,296,610		)	1,694,065
Total liabilities and equity	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,034,053		$	12,118		$	(633	)	$	3,045,538
COST OF SALES	—			—		2,928,036			1,327			(633		)	2,928,730
OPERATING COSTS AND EXPENSES:
Operating	—			—		68,750			4,505			—			73,255
General and administrative	—			—		27,686			240			—			27,926
Depreciation and amortization	—			—		47,740			2,863			—			50,603
Loss (gain) on disposal or impairment of assets, net	—			—		896			(44		)	—			852
Operating (Loss) Income	—			—		(39,055		)	3,227			—			(35,828		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		53			—			—			53
Interest expense	(16,364		)	—		(16,870		)	(291		)	83			(33,442		)
Gain on early extinguishment of liabilities	—			—		938			—			—			938
Other income, net	—			—		2,154			10			(83		)	2,081
(Loss) Income Before Income Taxes	(16,364		)	—		(52,780		)	2,946			—			(66,198		)
INCOME TAX EXPENSE	—			—		(460		)	—			—			(460		)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(50,235		)	—		3,005			—			47,230			—
Net (Loss) Income	(66,599		)	—		(50,235		)	2,946			47,230			(66,658		)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS												59			59
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(8,668		)	(8,668		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												45			45
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(66,599	)	$	—	$	(50,235	)	$	2,946		$	38,666		$	(75,222	)

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,153,370		$	49,442		$	(9,617	)	$	3,193,195
COST OF SALES	—			—		3,009,777			5,610			(9,561		)	3,005,826
OPERATING COSTS AND EXPENSES:
Operating	—			—		75,023			22,663			(56		)	97,630
General and administrative	—			—		24,538			4,760			—			29,298
Depreciation and amortization	—			—		45,006			11,755			—			56,761
Loss (gain) on disposal or impairment of assets, net	—			—		1,294			(3		)	—			1,291
Revaluation of liabilities	—			—		(15,909		)	—			—			(15,909		)
Operating Income	—			—		13,641			4,657			—			18,298
OTHER INCOME (EXPENSE):
Equity in (loss) earnings of unconsolidated entities	—			—		(23		)	2,455			—			2,432
Interest expense	(17,913		)	—		(11,351		)	(2,381		)	74			(31,571		)
Other income, net	—			—		1,916			113			(74		)	1,955
(Loss) Income Before Income Taxes	(17,913		)	—		4,183			4,844			—			(8,886		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,793			(7		)	—			2,786
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	8,316			—		1,340			—			(9,656		)	—
Net (Loss) Income	(9,597		)	—		8,316			4,837			(9,656		)	(6,100		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,497		)	(3,497		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,185		)	(16,185		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(9,597	)	$	—	$	8,316		$	4,837		$	(29,338	)	$	(25,782	)

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	5,749,034		$	19,469		$	(995	)	$	5,767,508
COST OF SALES	—			—		5,493,864			2,301			(995		)	5,495,170
OPERATING COSTS AND EXPENSES:
Operating	—			—		139,631			8,796			—			148,427
General and administrative	—			—		69,312			485			—			69,797
Depreciation and amortization	—			—		94,049			5,460			—			99,509
Gain on disposal or impairment of assets, net	—			—		(203,443		)	(24		)	—			(203,467		)
Operating Income	—			—		155,621			2,451			—			158,072
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		447			—			—			447
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(32,690		)	—		(30,898		)	(453		)	161			(63,880		)
Gain on early extinguishment of liabilities	8,614			—		22,276			—			—			30,890
Other income, net	—			—		5,990			24			(161		)	5,853
(Loss) Income Before Income Taxes	(24,076		)	—		139,071			2,022			—			117,017
INCOME TAX EXPENSE	—			—		(922		)	—			—			(922		)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	134,397			—		(3,752		)	—			(130,645		)	—
Net Income	110,321			—		134,397			2,022			(130,645		)	116,095
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(5,774		)	(5,774		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(12,052		)	(12,052		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(158		)	(158		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	110,321		$	—	$	134,397		$	2,022		$	(148,629	)	$	98,111

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	6,650,251		$	100,621		$	(19,208	)	$	6,731,664
COST OF SALES	—			—		6,333,438			14,022			(19,083		)	6,328,377
OPERATING COSTS AND EXPENSES:
Operating	—			—		160,323			43,022			(125		)	203,220
General and administrative	—			—		81,208			10,571			—			91,779
Depreciation and amortization	—			—		90,545			26,047			—			116,592
Loss (gain) on disposal or impairment of assets, net	—			—		1,715			(3		)	—			1,712
Revaluation of liabilities	—			—		(27,104		)	—			—			(27,104		)
Operating Income	—			—		10,126			6,962			—			17,088
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,872			8,278			—			11,150
Interest expense	(35,714		)	—		(22,344		)	(4,463		)	148			(62,373		)
Other income, net	—			—		691			237			(148		)	780
(Loss) Income Before Income Taxes	(35,714		)	—		(8,655		)	11,014			—			(33,355		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,286			(38		)	—			2,248
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(3,240		)	—		3,129			—			111			—
Net (Loss) Income	(38,954		)	—		(3,240		)	10,976			111			(31,107		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(7,847		)	(7,847		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(31,559		)	(31,559		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	(39,295	)	$	(70,513	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(66,599	)	$	—	$	(50,235	)	$	2,946	$	47,230	$	(66,658	)
Other comprehensive loss	—			—		(333		)	—		—		(333		)
Comprehensive (loss) income	$	(66,599	)	$	—	$	(50,568	)	$	2,946	$	47,230	$	(66,991	)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net (loss) income	$	(9,597	)	$	—	$	8,316	$	4,837		$	(9,656	)	$	(6,100	)
Other comprehensive loss	—			—		—		(19		)	—			(19		)
Comprehensive (loss) income	$	(9,597	)	$	—	$	8,316	$	4,818		$	(9,656	)	$	(6,119	)

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	110,321	$	—	$	134,397		$	2,022		$	(130,645	)	$	116,095
Other comprehensive loss	—		—		(475		)	(10		)	—			(485		)
Comprehensive income	$	110,321	$	—	$	133,922		$	2,012		$	(130,645	)	$	115,610

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	111	$	(31,107	)
Other comprehensive loss	—			—		—			(27		)	—		(27		)
Comprehensive (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,949		$	111	$	(31,134	)

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 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	$	(31,541	)	$	—	$	(12,751	)	$	(12,107	)	$	(56,399	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(158,333		)	(1,347		)	(159,680		)
Purchases of pipeline capacity allocations	—			—		(41,953		)	—			(41,953		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(113,297		)	—			(113,297		)
Cash flows from commodity derivatives	—			—		(25,015		)	—			(25,015		)
Proceeds from sales of assets	—			—		379			17			396
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Distributions of capital from unconsolidated entities	—			—		5,233			—			5,233
Payments on loan for natural gas liquids facility	—			—		4,324			—			4,324
Loan to affiliate	—			—		(1,700		)	—			(1,700		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash used in investing activities	—			—		(234,212		)	(1,330		)	(235,542		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		770,000			—			770,000
Payments on revolving credit facilities	—			—		(595,500		)	—			(595,500		)
Repurchases of senior notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(4,080		)	(343		)	(4,423		)
Debt issuance costs	(255		)	—		(65		)	—			(320		)
Contributions from partners	(442		)	—		—			—			(442		)
Contributions from noncontrolling interest owners	—			—		—			966			966
Distributions to partners	(83,707		)	—		—			—			(83,707		)
Distributions to noncontrolling interest owners	—			—		—			(2,750		)	(2,750		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018			—		—			—			235,018
Proceeds from sale of common units, net of offering costs	9,383			—		—			—			9,383
Payments for the early extinguishment of liabilities	—			—		(25,884		)	—			(25,884		)
Net changes in advances with consolidated entities	(128,960		)	—		113,907			15,053			—
Other	—			—		(20		)	—			(20		)
Net cash provided by financing activities	15,908			—		258,358			12,926			287,192
Net (decrease) increase in cash and cash equivalents	(15,633		)	—		11,395			(511		)	(4,749		)
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	10,116		$	—	$	12,179		$	1,132		$	23,427

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2015
	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	$	(34,469	)	$	—	$	173,058		$	35,506		$	174,095
INVESTING ACTIVITIES:
Capital expenditures	—			—		(184,680		)	(37,596		)	(222,276		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(150,546		)	—			(150,546		)
Cash flows from commodity derivatives	—			—		43,032			—			43,032
Proceeds from sales of assets	—			—		3,565			2			3,567
Investments in unconsolidated entities	—			—		(2,700		)	(4,226		)	(6,926		)
Distributions of capital from unconsolidated entities	—			—		5,652			2,555			8,207
Loan for natural gas liquids facility	—			—		(3,913		)	—			(3,913		)
Payments on loan for natural gas liquids facility	—			—		3,546			—			3,546
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Net cash used in investing activities	—			—		(301,665		)	(39,265		)	(340,930		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,311,500			43,200			1,354,700
Payments on revolving credit facilities	—			—		(963,000		)	(43,600		)	(1,006,600		)
Payments on other long-term debt	—			—		(2,274		)	(70		)	(2,344		)
Debt issuance costs	49			—		(180		)	(1,249		)	(1,380		)
Contributions from partners	45			—		—			—			45
Contributions from noncontrolling interest owners	—			—		—			6,613			6,613
Distributions to partners	(154,824		)	—		—			—			(154,824		)
Distributions to noncontrolling interest owners	—			—		—			(17,780		)	(17,780		)
Taxes paid on behalf of equity incentive plan participants	—			—		(19,083		)	—			(19,083		)
Common unit repurchases	(3,650		)	—		—			—			(3,650		)
Net changes in advances with consolidated entities	186,776			—		(203,533		)	16,757			—
Other	—			—		(33		)	(79		)	(112		)
Net cash provided by financing activities	28,396			—		123,397			3,792			155,585
Net (decrease) increase in cash and cash equivalents	(6,073		)	—		(5,210		)	33			(11,250		)
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	23,042		$	—	$	4,547		$	2,464		$	30,053

XML

Significant Accounting Policies (Policies)

6 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Basis of Presentation

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. We have included 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, 2016 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2016 included in our Annual Report on Form 10-K (“Annual Report”).

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment.The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction.We have restated our previously issued condensed consolidated statements of operations and condensed consolidated statements of comprehensive loss for the three months andsix months endedSeptember 30, 2015 and condensed consolidated statement of cash flows for the six months endedSeptember 30, 2015. See Note 17in our Annual Reportfor a summary of the impact of the error correction for the three months andsix months endedSeptember 30, 2015.

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, 2017.

Use of Estimates

Use of Estimates

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

Critical estimates we make in the preparation of our condensed consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations, the 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 various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

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. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

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

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

Derivative Financial Instruments

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our 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 non-cash mark-to-market adjustments) are reported within cost of sales in our 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 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

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.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Supplemental Cash Flow Information

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

Inventories

Inventories

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

Investments in Unconsolidated Entities

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are 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 condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our condensed consolidated statements of cash flows.

Noncontrolling Interests

Noncontrolling Interests

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

Business Combination Measurement Period

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 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.

Also, as discussed in Note 4, we made certain adjustments during the three months endedSeptember 30, 2016 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the fiscal year ended March 31, 2016.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, “Simplifying the Accounting Adjustments for Measurement-Period Adjustments.” The ASU requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for the Partnership beginning April 1, 2016, and required a prospective method of adoption.

Reclassifications

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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

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

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires a prospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our consolidated financial position or results of operations.

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 determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

XML

Significant Accounting Policies (Tables)

6 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Schedule of supplemental cash flow information

Non-cash investing and financing activities and supplemental disclosures of cash flow information are as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Value of common units issued in business combinations	$	3,969	$	—	$	3,969	$	11,367
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash interest paid	$	29,711	$	26,323	$	58,869	$	57,495
Income taxes paid (net of income tax refunds)	71		533		1,755		4,616

Schedule of inventories

Inventories consist of the following at the dates indicated:

	September 30, 2016		March 31, 2016
	(in thousands)
Crude oil	$	86,495	$	84,030
Natural gas liquids:
Propane	73,704		28,639
Butane	44,929		8,461
Other	5,936		6,011
Refined products:
Gasoline	126,821		80,569
Diesel	138,245		99,398
Renewables	34,328		52,458
Other	9,882		8,240
Total	$	520,340	$	367,806

Schedule of investments in unconsolidated entities

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

Entity	Segment	Ownership Interest	Date Acquired or Formed	September 30, 2016		March 31, 2016
				(in thousands)
Glass Mountain (1)	Crude Oil Logistics	50%	December 2013	$	174,364	$	179,594
Ethanol production facility	Refined Products and Renewables	19%	December 2013	13,507		12,570
Water treatment and disposal facility	Water Solutions	50%	August 2015	2,235		2,238
Retail propane company	Retail Propane	50%	April 2015	556		972
TLP (2)	Refined Products and Renewables	0%	July 2014	—		8,301
Water supply company (3)	Water Solutions	100%	June 2014	—		15,875
Total				$	190,662	$	219,550

(1) When we acquired Gavilon, LLC, (“Gavilon Energy”), we recorded the investment in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $73.6 million at September 30, 2016. This difference relates primarily to goodwill and customer relationships.

(2) On April 1, 2016, we sold all of the TLP common units we owned.

(3) On June 3, 2016, we acquired the remaining65%ownership interest inthe water supply company, and as a result, the water supply company is now consolidated in our condensed consolidated financial statements (see Note 4).

Schedule of other noncurrent assets

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

	September 30, 2016		March 31, 2016
	(in thousands)
Loan receivable (1)	$	44,957	$	49,827
Tank bottoms (2)	42,044		42,044
Line fill (3)	35,013		35,060
Other	95,725		49,108
Total	$	217,739	$	176,039

(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) 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 September 30, 2016 and March 31, 2016, 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).

(3) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2016 and March 31, 2016, line fill consisted of 486,473 barrels and 487,104 barrels of crude oil, respectively.

Schedule of accrued expenses and other payables

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

	September 30, 2016		March 31, 2016
	(in thousands)
Accrued compensation and benefits	$	19,322	$	40,517
Excise and other tax liabilities	56,147		59,455
Derivative liabilities	31,959		28,612
Accrued interest	19,594		20,543
Product exchange liabilities	7,045		5,843
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	20,454		29,343
Total	$	184,634	$	214,426

XML

Income (Loss) Per Common Unit (Tables)

6 Months Ended

Sep. 30, 2016

Earnings Per Unit [Abstract]

Schedule of income (loss) per common unit

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

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except unit and per unit amounts)
Net (loss) income	$	(66,658	)	$	(6,100	)	$	116,095		$	(31,107	)
Less: Net loss (income) attributable to noncontrolling interests	59			(3,497		)	(5,774		)	(7,847		)
Net (loss) income attributable to NGL Energy Partners LP	(66,599		)	(9,597		)	110,321			(38,954		)
Less: Distributions to preferred unitholders	(8,668		)	—			(12,052		)	—
Less: Net loss (income) allocated to general partner (1)	45			(16,185		)	(158		)	(31,559		)
Net (loss) income allocated to common unitholders	$	(75,222	)	$	(25,782	)	$	98,111		$	(70,513	)
Basic (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.93		$	(0.67	)
Diluted (loss) income per common unit	$	(0.71	)	$	(0.25	)	$	0.91		$	(0.67	)
Basic weighted average common units outstanding	106,186,389			105,189,463			105,183,556			104,542,427
Diluted weighted average common units outstanding	106,186,389			105,189,463			107,997,549			104,542,427

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

XML

Acquisitions (Tables)

6 Months Ended

Sep. 30, 2016

Water Solutions Acquisitions 2017 Acquisitions

Business Acquisition [Line Items]

Schedule of the fair values (and useful lives) of the assets acquired and liabilities assumed

The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Property, plant and equipment	$	15,021
Goodwill	18,933
Intangible assets	3,878
Current liabilities	(1,239		)
Other noncurrent liabilities	(9,697		)
Fair value of net assets acquired	$	26,896

Water supply company

Business Acquisition [Line Items]

Schedule of the fair values (and useful lives) of the assets acquired and liabilities assumed

The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	1,713
Property, plant and equipment	8,874
Intangible asset	14,472
Current liabilities	(2,765		)
Notes payable-intercompany	(19,900		)
Fair value of net assets acquired	$	2,394

Retail propane 2017 acquisitions

Business Acquisition [Line Items]

Schedule of the fair values (and useful lives) of the assets acquired and liabilities assumed

The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):

Current assets	$	6,282
Property, plant and equipment	30,576
Goodwill	9,419
Intangible assets	36,950
Current liabilities	(5,555		)
Other noncurrent liabilities	(1,587		)
Fair value of net assets acquired	$	76,085

XML

Property, Plant and Equipment (Tables)

6 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Schedule of property, plant and equipment

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

Description	Estimated Useful Lives	September 30, 2016			March 31, 2016
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	168,754		$	169,758
Refined products terminal assets and equipment	20 years	6,844			6,844
Retail propane equipment	2–30 years	227,442			201,312
Vehicles and railcars	3–25 years	194,291			185,547
Water treatment facilities and equipment	3–30 years	535,255			508,239
Crude oil tanks and related equipment	2–40 years	140,245			137,894
Barges and towboats	5–40 years	89,973			86,731
Information technology equipment	3–7 years	42,218			38,653
Buildings and leasehold improvements	3–40 years	123,005			118,885
Land		50,132			47,114
Tank bottoms		20,105			20,355
Other	3–30 years	56,450			11,699
Construction in progress		425,066			383,032
		2,079,780			1,916,063
Accumulated depreciation		(324,364		)	(266,491		)
Net property, plant and equipment		$	1,755,416		$	1,649,572

Schedule of depreciation expense and capitalized interest expense

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Depreciation expense	$	28,703	$	34,469	$	56,357	$	70,264
Capitalized interest expense	1,069		549		4,804		690

Summary of tank bottoms

The following table summarizes the tank bottoms included in the table above at the dates indicated:

	September 30, 2016			March 31, 2016
Product	Volume (in barrels) (in thousands)	Value (in thousands)		Volume (in barrels) (in thousands)	Value (in thousands)
Crude oil	229	$	19,120	231	$	19,348
Other	24	985		24	1,007
Total		$	20,105		$	20,355

XML

Goodwill (Tables)

6 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of goodwill by segment, including changes to goodwill

The following table summarizes changes in goodwill by segment during the six months endedSeptember 30, 2016:

	Crude Oil Logistics		Water Solutions			Liquids		Retail Propane			Refined Products and Renewables		Total
	(in thousands)
Balances at March 31, 2016	$	579,846	$	290,915		$	266,046	$	127,428		$	51,127	$	1,315,362
Revisions to acquisition accounting (Note 4)	—		(419		)	—		(2		)	—		(421		)
Acquisitions (Note 4)	—		18,933			—		9,419			—		28,352
Adjustment to initial impairment estimate	—		124,662			—		—			—		124,662
Balances at September 30, 2016	$	579,846	$	434,091		$	266,046	$	136,845		$	51,127	$	1,467,955

XML

Intangible Assets (Tables)

6 Months Ended

Sep. 30, 2016

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Schedule of intangible assets

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

		September 30, 2016						March 31, 2016
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	883,896	$	274,111	$	609,785	$	852,118	$	233,838	$	618,280
Pipeline capacity rights	30 years	161,589		8,957		152,632		119,636		6,559		113,077
Water facility development agreement	5 years	—		—		—		14,000		7,700		6,300
Executory contracts and other agreements	2–30 years	22,713		19,699		3,014		23,920		21,075		2,845
Non-compete agreements	2–32 years	31,784		15,101		16,683		20,903		13,564		7,339
Trade names	1–10 years	15,439		12,882		2,557		15,439		12,034		3,405
Debt issuance costs (1)	3 years	39,977		25,564		14,413		39,942		22,108		17,834
Total amortizable		1,155,398		356,314		799,084		1,085,958		316,878		769,080
Non-amortizable:
Customer commitments		310,000		—		310,000		310,000		—		310,000
Rights-of-way and easements		47,721		—		47,721		47,190		—		47,190
Water rights		14,472		—		14,472		—		—		—
Trade names		18,870		—		18,870		22,620		—		22,620
Total non-amortizable		391,063		—		391,063		379,810		—		379,810
Total		$	1,546,461	$	356,314	$	1,190,147	$	1,465,768	$	316,878	$	1,148,890

(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.

Schedule of amortization expense

Amortization expense is as follows for the periods indicated:

	Three Months Ended September 30,				Six Months Ended September 30,
Recorded In	2016		2015		2016		2015
	(in thousands)
Depreciation and amortization	$	21,900	$	22,291	$	43,152	$	46,328
Cost of sales	1,749		1,700		3,345		3,401
Interest expense	1,731		1,470		3,456		2,954
Total	$	25,380	$	25,461	$	49,953	$	52,683

Schedule of expected amortization of intangible assets

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

Year Ending March 31,
2017 (six months)	$	51,028
2018	98,717
2019	89,701
2020	82,185
2021	69,422
Thereafter	408,031
Total	$	799,084

XML

Long-Term Debt (Tables)

6 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of long-term debt

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

	September 30, 2016							March 31, 2016
	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	$	1,312,000	$	—		$	1,312,000	$	1,229,500	$	—		$	1,229,500
Working capital borrowings	710,500		—			710,500		618,500		—			618,500
5.125% Notes due 2019	383,467		(3,871		)	379,596		388,467		(4,681		)	383,786
6.875% Notes due 2021	369,063		(6,433		)	362,630		388,289		(7,545		)	380,744
6.650% Notes due 2022	250,000		(3,055		)	246,945		250,000		(3,166		)	246,834
Other long-term debt	59,506		(123		)	59,383		61,488		(108		)	61,380
	3,084,536		(13,482		)	3,071,054		2,936,244		(15,500		)	2,920,744
Less: Current maturities	8,046		—			8,046		7,907		—			7,907
Long-term debt	$	3,076,490	$	(13,482	)	$	3,063,008	$	2,928,337	$	(15,500	)	$	2,912,837

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

Schedule of future amortization expense of debt issuance costs

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

Year Ending March 31,
2017 (six months)	$	1,619
2018	3,229
2019	3,226
2020	2,236
2021	1,827
Thereafter	1,345
Total	$	13,482

Schedule of maturities of long-term debt

The scheduled maturities of our long-term debt are as follows at September 30, 2016:

Year Ending March 31,	Revolving Credit Facility		2019 Notes		2021 Notes		2022 Notes		Other Long-Term Debt		Total
	(in thousands)
2017 (six months)	$	—	$	—	$	—	$	—	$	3,405	$	3,405
2018	—		—		—		25,000		8,014		33,014
2019	2,022,500		—		—		50,000		6,857		2,079,357
2020	—		383,467		—		50,000		6,372		439,839
2021	—		—		—		50,000		34,728		84,728
Thereafter	—		—		369,063		75,000		130		444,193
Total	$	2,022,500	$	383,467	$	369,063	$	250,000	$	59,506	$	3,084,536

XML

Commitments and Contingencies (Tables)

6 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of change in asset retirement obligation

The following table is a rollforward of our asset retirement obligation, which is reported within other noncurrent liabilities in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2016	$	5,574
Liabilities assumed in acquisitions	406
Accretion expense	207
Balance at September 30, 2016	$	6,187

Schedule of future minimum lease payments under contractual commitments

The following table summarizes future minimum lease payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	67,837
2018	122,935
2019	101,047
2020	90,112
2021	80,457
Thereafter	135,486
Total	$	597,874

Schedule of future minimum throughput payments under agreements

The following table summarizes future minimum throughput payments under these agreements at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	26,008
2018	52,082
2019	52,170
2020	42,418
Total	$	172,678

Schedule of outstanding sales and purchase contracts

The following table summarizes such commitments at September 30, 2016:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	35,592	$	18,710
Natural gas liquids index-price (gallons)	587,044	347,020
Crude oil fixed-price (barrels)	1,993	88,079
Crude oil index-price (barrels)	14,466	655,273
Sale commitments:
Natural gas liquids fixed-price (gallons)	163,546	105,868
Natural gas liquids index-price (gallons)	414,042	317,983
Crude oil fixed-price (barrels)	3,415	152,584
Crude oil index-price (barrels)	12,953	637,731

XML

Equity (Tables)

6 Months Ended

Sep. 30, 2016

Equity

Schedule of dividends declared

The following table summarizes distributions declared for the last three 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 21, 2016	May 3, 2016	May 13, 2016	$	0.3900	$	40,626	$	70
July 22, 2016	August 4, 2016	August 12, 2016	0.3900		41,146		71
October 20, 2016	November 4, 2016	November 14, 2016	0.3900		41,907		72

Service awards

Equity

Schedule of service awards activity

The following table summarizes the Service Award activity during the six months endedSeptember 30, 2016:

Unvested Service Award units at March 31, 2016	2,297,132
Units granted	3,048,100
Units vested and issued	(2,340,082	)
Units forfeited	(322,100	)
Unvested Service Award units at September 30, 2016	2,683,050

Summary of scheduled vesting of awards

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

Year Ending March 31,
2017 (six months)	10,000
2018	887,350
2019	894,800
Thereafter	890,900
Unvested Service Award units at September 30, 2016	2,683,050

Schedule of estimated equity-based expense to be recorded on the awards granted

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	9,329
2018	12,239
2019	8,853
Thereafter	2,317
Total	$	32,738

Performance awards

Equity

Schedule of service awards activity

The following table summarizes the Performance Award activity during the six months ended September 30, 2016:

Unvested Performance Award units at March 31, 2016	637,382
Units granted	932,309
Units forfeited	(380,691	)
Unvested Performance Award units at September 30, 2016	1,189,000

Schedule of estimated equity-based expense to be recorded on the awards granted

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2016 (in thousands):

Year Ending March 31,
2017 (six months)	$	4,138
2018	6,197
2019	3,232
Thereafter	655
Total	$	14,222

Schedule of performance measurement period for each tranche

As of September 30, 2016, 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

Summary of percentage of the maximum performance award units that will vest depending on the percentage of entities in the Index that NGL outperforms

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

Our Relative Total Unitholder Return Percentile Ranking	Payout (% of Target Units)
Less than 50th percentile	0%
Between the 50th and 75th percentile	50%–100%
Between the 75th and 90th percentile	100%–200%
Above the 90% percentile	200%

XML

Fair Value of Financial Instruments (Tables)

6 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of estimated fair value measurements of assets and liabilities

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

	September 30, 2016						March 31, 2016
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	2,512		$	(40,260	)	$	47,361		$	(3,983	)
Level 2 measurements	42,455			(32,253		)	32,700			(28,612		)
	44,967			(72,513		)	80,061			(32,595		)
Netting of counterparty contracts (1)	(3,091		)	3,091			(3,384		)	3,384
Net cash collateral provided (held)	21			37,463			(18,176		)	599
Commodity derivatives in condensed consolidated balance sheet	$	41,897		$	(31,959	)	$	58,501		$	(28,612	)

(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.

Schedule of location of commodity derivative assets and liabilities reported on the condensed consolidated balance sheets

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

	September 30, 2016			March 31, 2016
	(in thousands)
Prepaid expenses and other current assets	$	41,897		$	58,501
Accrued expenses and other payables	(31,959		)	(28,612		)
Net commodity derivative asset	$	9,938		$	29,889

Summary of open commodity derivative contract positions

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 September 30, 2016:
Cross-commodity (1)	October 2016–March 2017	126		$	1,465
Crude oil fixed-price (2)	October 2016–December 2016	(588	)	(3,041		)
Propane fixed-price (2)	October 2016–December 2017	462		518
Refined products fixed-price (2)	October 2016–September 2017	(5,628	)	(22,607		)
Other	October 2016–March 2022			(3,881		)
				(27,546		)
Net cash collateral provided				37,484
Net commodity derivative asset in condensed consolidated balance sheet				$	9,938
At March 31, 2016:
Cross-commodity (1)	April 2016–March 2017	251		$	1,663
Crude oil fixed-price (2)	April 2016–December 2016	(1,583	)	(3,655		)
Propane fixed-price (2)	April 2016–December 2017	540		(592		)
Refined products fixed-price (2)	April 2016–June 2017	(5,355	)	48,557
Other	April 2016–March 2017			1,493
				47,466
Net cash collateral held				(17,577		)
Net commodity derivative asset in condensed consolidated balance sheet				$	29,889

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

(2) 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.

Schedule of fair value estimates of fixed-rate notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2016 (in thousands):

2019 Notes	$	360,459
2021 Notes	349,995
2022 Notes	253,838

XML

Segments (Tables)

6 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Schedule of certain information related to results of operations by segment

				As Restated						As Restated
	Three Months Ended September 30,						Six Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	341,981		$	997,106		$	756,600		$	2,309,889
Crude oil transportation and other	9,172			12,746			22,106			31,695
Elimination of intersegment sales	(1,268		)	(2,274		)	(2,870		)	(6,222		)
Total Crude Oil Logistics revenues	349,885			1,007,578			775,836			2,335,362
Water Solutions:
Service fees	28,528			35,203			54,225			71,941
Recovered hydrocarbons	5,681			10,746			12,877			26,564
Other revenues	5,524			1,545			8,384			3,282
Total Water Solutions revenues	39,733			47,494			75,486			101,787
Liquids:
Propane sales	101,613			98,770			198,084			204,260
Other product sales	135,700			160,836			249,435			308,347
Other revenues	8,075			10,122			15,222			19,622
Elimination of intersegment sales	(11,128		)	(10,736		)	(23,432		)	(24,252		)
Total Liquids revenues	234,260			258,992			439,309			507,977
Retail Propane:
Propane sales	36,170			36,119			77,811			79,304
Distillate sales	5,589			7,678			16,044			20,625
Other revenues	9,331			9,409			17,638			17,724
Elimination of intersegment sales	—			—			(16		)	—
Total Retail Propane revenues	51,090			53,206			111,477			117,653
Refined Products and Renewables:
Refined products sales	2,274,715			1,704,259			4,151,572			3,413,208
Renewables sales	95,830			93,189			202,312			199,342
Service fees	(121		)	28,739			11,145			56,812
Elimination of intersegment sales	(102		)	(262		)	(144		)	(477		)
Total Refined Products and Renewables revenues	2,370,322			1,825,925			4,364,885			3,668,885
Corporate and Other	248			—			515			—
Total revenues	$	3,045,538		$	3,193,195		$	5,767,508		$	6,731,664
Depreciation and Amortization:
Crude Oil Logistics	$	9,025		$	10,053		$	17,993		$	20,055
Water Solutions	25,129			22,416			49,563			43,262
Liquids	4,425			2,745			8,874			7,749
Retail Propane	10,705			8,909			20,392			17,615
Refined Products and Renewables	416			11,152			833			25,327
Corporate and Other	903			1,486			1,854			2,584
Total depreciation and amortization	$	50,603		$	56,761		$	99,509		$	116,592
Operating Income (Loss):
Crude Oil Logistics	$	(19,039	)	$	(75	)	$	(19,664	)	$	11,885
Water Solutions	(4,430		)	18,257			75,034			28,704
Liquids	8,384			20,370			8,327			19,899
Retail Propane	(8,717		)	(1,765		)	(11,219		)	(2,465		)
Refined Products and Renewables	11,387			(5,244		)	161,156			27,776
Corporate and Other	(23,413		)	(13,245		)	(55,562		)	(68,711		)
Total operating (loss) income	$	(35,828	)	$	18,298		$	158,072		$	17,088

Schedule of additions to property, plant and equipment by segment

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 September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Crude Oil Logistics	$	32,397	$	44,384	$	104,702	$	107,023
Water Solutions	25,237		72,531		68,353		133,020
Liquids	6,693		18,886		13,161		36,064
Retail Propane	71,425		15,814		77,974		22,709
Refined Products and Renewables	1,143		7,588		1,167		23,283
Corporate and Other	614		—		1,732		1,169
Total	$	137,509	$	159,203	$	267,089	$	323,268

Schedule of long-lived assets (consisting of property, plant and equipment, intangible assets and goodwill) and total assets by segment

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:

	September 30, 2016		March 31, 2016
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,720,278	$	1,679,027
Water Solutions	1,316,196		1,162,405
Liquids	575,963		572,081
Retail Propane	549,429		483,330
Refined Products and Renewables	219,157		180,783
Corporate and Other	32,495		36,198
Total	$	4,413,518	$	4,113,824
Total assets:
Crude Oil Logistics	$	2,318,083	$	2,197,113
Water Solutions	1,354,786		1,236,875
Liquids	785,303		693,872
Retail Propane	611,340		538,267
Refined Products and Renewables	904,386		765,806
Corporate and Other	100,020		128,222
Total	$	6,073,918	$	5,560,155

XML

Transactions with Affiliates (Tables)

6 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Summary of purchase and sales transactions of products and services

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

	Three Months Ended September 30,				Six Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Sales to SemGroup	$	3,513	$	4,593	$	3,584	$	42,031
Purchases from SemGroup	1,938		6,478		3,963		45,303
Sales to equity method investees	95		1,696		500		3,086
Purchases from equity method investees	27,345		24,816		57,992		55,764
Sales to entities affiliated with management	75		91		152		198
Purchases from entities affiliated with management	3,493		16,214		11,736		23,394

Schedule of accounts receivable from affiliates

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

	September 30, 2016		March 31, 2016
	(in thousands)
Receivables from SemGroup	$	3,401	$	1,166
Receivables from equity method investees	—		14,446
Receivables from entities affiliated with management	139		13
Total	$	3,540	$	15,625

Schedule of accounts payable to affiliates

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

	September 30, 2016		March 31, 2016
	(in thousands)
Payables to SemGroup	$	4,015	$	1,823
Payables to equity method investees	1,155		3,947
Payables to entities affiliated with management	1,074		1,423
Total	$	6,244	$	7,193

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Tables)

6 Months Ended

Sep. 30, 2016

Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Schedule of Condensed Consolidating Balance Sheets

	March 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,749	$	—	$	784		$	1,643		$	—		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		516,362			4,652			—			521,014
Accounts receivable-affiliates	—		—		15,625			—			—			15,625
Inventories	—		—		367,250			556			—			367,806
Prepaid expenses and other current assets	—		—		94,426			1,433			—			95,859
Total current assets	25,749		—		994,447			8,284			—			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,568,488			81,084			—			1,649,572
GOODWILL	—		—		1,313,364			1,998			—			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,146,355			2,535			—			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		219,550			—			—			219,550
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,404,479		—		(1,402,360		)	(2,119		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,254,383		—		42,227			—			(1,296,610		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		22,262			—			—			22,262
OTHER NONCURRENT ASSETS	—		—		175,512			527			—			176,039
Total assets	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	417,707		$	2,599		$	—		$	420,306
Accounts payable-affiliates	1		—		7,190			2			—			7,193
Accrued expenses and other payables	16,887		—		196,596			943			—			214,426
Advance payments received from customers	—		—		55,737			448			—			56,185
Current maturities of long-term debt	—		—		7,109			798			—			7,907
Total current liabilities	16,888		—		684,339			4,790			—			706,017
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,011,365		—		1,894,428			7,044			—			2,912,837
OTHER NONCURRENT LIABILITIES	—		—		246,695			541			—			247,236
EQUITY:
Partners’ equity	1,656,358		—		1,254,384			80,090			(1,334,317		)	1,656,515
Accumulated other comprehensive loss	—		—		(1		)	(156		)	—			(157		)
Noncontrolling interests	—		—		—			—			37,707			37,707
Total equity	1,656,358		—		1,254,383			79,934			(1,296,610		)	1,694,065
Total liabilities and equity	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155

	September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,116	$	—	$	12,179		$	1,132		$	—		$	23,427
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		585,720			6,354			—			592,074
Accounts receivable-affiliates	—		—		3,540			—			—			3,540
Inventories	—		—		519,795			545			—			520,340
Prepaid expenses and other current assets	—		—		109,969			949			—			110,918
Total current assets	10,116		—		1,231,203			8,980			—			1,250,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,653,011			102,405			—			1,755,416
GOODWILL	—		—		1,448,661			19,294			—			1,467,955
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,166,439			23,708			—			1,190,147
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		190,662			—			—			190,662
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,290,616		—		(1,279,908		)	(10,708		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,689,633		—		96,577			—			(1,786,210		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		1,700			—			—			1,700
OTHER NONCURRENT ASSETS	—		—		217,618			121			—			217,739
Total assets	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918
LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	510,535		$	1,569		$	—		$	512,104
Accounts payable-affiliates	1		—		6,054			189			—			6,244
Accrued expenses and other payables	16,232		—		164,918			3,484			—			184,634
Advance payments received from customers	—		—		87,094			731			—			87,825
Current maturities of long-term debt	—		—		7,252			794			—			8,046
Total current liabilities	16,233		—		775,853			6,767			—			798,853
LONG-TERM DEBT, net of debt issuance costs and current maturities	989,171		—		2,067,264			6,573			—			3,063,008
OTHER NONCURRENT LIABILITIES	—		—		193,213			4,788			—			198,001
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	58,742		—		—			—			—			58,742
EQUITY:
Partners’ equity	1,926,219		—		1,690,096			125,851			(1,815,305		)	1,926,861
Accumulated other comprehensive loss	—		—		(463		)	(179		)	—			(642		)
Noncontrolling interests	—		—		—			—			29,095			29,095
Total equity	1,926,219		—		1,689,633			125,672			(1,786,210		)	1,955,314
Total liabilities, convertible preferred units and equity	$	2,990,365	$	—	$	4,725,963		$	143,800		$	(1,786,210	)	$	6,073,918

Schedule of Condensed Consolidating Statements of Operations

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	5,749,034		$	19,469		$	(995	)	$	5,767,508
COST OF SALES	—			—		5,493,864			2,301			(995		)	5,495,170
OPERATING COSTS AND EXPENSES:
Operating	—			—		139,631			8,796			—			148,427
General and administrative	—			—		69,312			485			—			69,797
Depreciation and amortization	—			—		94,049			5,460			—			99,509
Gain on disposal or impairment of assets, net	—			—		(203,443		)	(24		)	—			(203,467		)
Operating Income	—			—		155,621			2,451			—			158,072
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		447			—			—			447
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(32,690		)	—		(30,898		)	(453		)	161			(63,880		)
Gain on early extinguishment of liabilities	8,614			—		22,276			—			—			30,890
Other income, net	—			—		5,990			24			(161		)	5,853
(Loss) Income Before Income Taxes	(24,076		)	—		139,071			2,022			—			117,017
INCOME TAX EXPENSE	—			—		(922		)	—			—			(922		)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	134,397			—		(3,752		)	—			(130,645		)	—
Net Income	110,321			—		134,397			2,022			(130,645		)	116,095
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(5,774		)	(5,774		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(12,052		)	(12,052		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(158		)	(158		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	110,321		$	—	$	134,397		$	2,022		$	(148,629	)	$	98,111

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,034,053		$	12,118		$	(633	)	$	3,045,538
COST OF SALES	—			—		2,928,036			1,327			(633		)	2,928,730
OPERATING COSTS AND EXPENSES:
Operating	—			—		68,750			4,505			—			73,255
General and administrative	—			—		27,686			240			—			27,926
Depreciation and amortization	—			—		47,740			2,863			—			50,603
Loss (gain) on disposal or impairment of assets, net	—			—		896			(44		)	—			852
Operating (Loss) Income	—			—		(39,055		)	3,227			—			(35,828		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		53			—			—			53
Interest expense	(16,364		)	—		(16,870		)	(291		)	83			(33,442		)
Gain on early extinguishment of liabilities	—			—		938			—			—			938
Other income, net	—			—		2,154			10			(83		)	2,081
(Loss) Income Before Income Taxes	(16,364		)	—		(52,780		)	2,946			—			(66,198		)
INCOME TAX EXPENSE	—			—		(460		)	—			—			(460		)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(50,235		)	—		3,005			—			47,230			—
Net (Loss) Income	(66,599		)	—		(50,235		)	2,946			47,230			(66,658		)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS												59			59
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(8,668		)	(8,668		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												45			45
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(66,599	)	$	—	$	(50,235	)	$	2,946		$	38,666		$	(75,222	)

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	6,650,251		$	100,621		$	(19,208	)	$	6,731,664
COST OF SALES	—			—		6,333,438			14,022			(19,083		)	6,328,377
OPERATING COSTS AND EXPENSES:
Operating	—			—		160,323			43,022			(125		)	203,220
General and administrative	—			—		81,208			10,571			—			91,779
Depreciation and amortization	—			—		90,545			26,047			—			116,592
Loss (gain) on disposal or impairment of assets, net	—			—		1,715			(3		)	—			1,712
Revaluation of liabilities	—			—		(27,104		)	—			—			(27,104		)
Operating Income	—			—		10,126			6,962			—			17,088
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,872			8,278			—			11,150
Interest expense	(35,714		)	—		(22,344		)	(4,463		)	148			(62,373		)
Other income, net	—			—		691			237			(148		)	780
(Loss) Income Before Income Taxes	(35,714		)	—		(8,655		)	11,014			—			(33,355		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,286			(38		)	—			2,248
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(3,240		)	—		3,129			—			111			—
Net (Loss) Income	(38,954		)	—		(3,240		)	10,976			111			(31,107		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(7,847		)	(7,847		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(31,559		)	(31,559		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	(39,295	)	$	(70,513	)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—	$	3,153,370		$	49,442		$	(9,617	)	$	3,193,195
COST OF SALES	—			—		3,009,777			5,610			(9,561		)	3,005,826
OPERATING COSTS AND EXPENSES:
Operating	—			—		75,023			22,663			(56		)	97,630
General and administrative	—			—		24,538			4,760			—			29,298
Depreciation and amortization	—			—		45,006			11,755			—			56,761
Loss (gain) on disposal or impairment of assets, net	—			—		1,294			(3		)	—			1,291
Revaluation of liabilities	—			—		(15,909		)	—			—			(15,909		)
Operating Income	—			—		13,641			4,657			—			18,298
OTHER INCOME (EXPENSE):
Equity in (loss) earnings of unconsolidated entities	—			—		(23		)	2,455			—			2,432
Interest expense	(17,913		)	—		(11,351		)	(2,381		)	74			(31,571		)
Other income, net	—			—		1,916			113			(74		)	1,955
(Loss) Income Before Income Taxes	(17,913		)	—		4,183			4,844			—			(8,886		)
INCOME TAX BENEFIT (EXPENSE)	—			—		2,793			(7		)	—			2,786
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	8,316			—		1,340			—			(9,656		)	—
Net (Loss) Income	(9,597		)	—		8,316			4,837			(9,656		)	(6,100		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(3,497		)	(3,497		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,185		)	(16,185		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(9,597	)	$	—	$	8,316		$	4,837		$	(29,338	)	$	(25,782	)

Schedule of Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(66,599	)	$	—	$	(50,235	)	$	2,946	$	47,230	$	(66,658	)
Other comprehensive loss	—			—		(333		)	—		—		(333		)
Comprehensive (loss) income	$	(66,599	)	$	—	$	(50,568	)	$	2,946	$	47,230	$	(66,991	)

	As Restated
	Three Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net (loss) income	$	(9,597	)	$	—	$	8,316	$	4,837		$	(9,656	)	$	(6,100	)
Other comprehensive loss	—			—		—		(19		)	—			(19		)
Comprehensive (loss) income	$	(9,597	)	$	—	$	8,316	$	4,818		$	(9,656	)	$	(6,119	)

	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	110,321	$	—	$	134,397		$	2,022		$	(130,645	)	$	116,095
Other comprehensive loss	—		—		(475		)	(10		)	—			(485		)
Comprehensive income	$	110,321	$	—	$	133,922		$	2,012		$	(130,645	)	$	115,610

	As Restated
	Six Months Ended September 30, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,976		$	111	$	(31,107	)
Other comprehensive loss	—			—		—			(27		)	—		(27		)
Comprehensive (loss) income	$	(38,954	)	$	—	$	(3,240	)	$	10,949		$	111	$	(31,134	)

Schedule of Condensed Consolidating Statements of Cash Flows

	Six Months Ended September 30, 2015
	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	$	(34,469	)	$	—	$	173,058		$	35,506		$	174,095
INVESTING ACTIVITIES:
Capital expenditures	—			—		(184,680		)	(37,596		)	(222,276		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(150,546		)	—			(150,546		)
Cash flows from commodity derivatives	—			—		43,032			—			43,032
Proceeds from sales of assets	—			—		3,565			2			3,567
Investments in unconsolidated entities	—			—		(2,700		)	(4,226		)	(6,926		)
Distributions of capital from unconsolidated entities	—			—		5,652			2,555			8,207
Loan for natural gas liquids facility	—			—		(3,913		)	—			(3,913		)
Payments on loan for natural gas liquids facility	—			—		3,546			—			3,546
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Net cash used in investing activities	—			—		(301,665		)	(39,265		)	(340,930		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,311,500			43,200			1,354,700
Payments on revolving credit facilities	—			—		(963,000		)	(43,600		)	(1,006,600		)
Payments on other long-term debt	—			—		(2,274		)	(70		)	(2,344		)
Debt issuance costs	49			—		(180		)	(1,249		)	(1,380		)
Contributions from partners	45			—		—			—			45
Contributions from noncontrolling interest owners	—			—		—			6,613			6,613
Distributions to partners	(154,824		)	—		—			—			(154,824		)
Distributions to noncontrolling interest owners	—			—		—			(17,780		)	(17,780		)
Taxes paid on behalf of equity incentive plan participants	—			—		(19,083		)	—			(19,083		)
Common unit repurchases	(3,650		)	—		—			—			(3,650		)
Net changes in advances with consolidated entities	186,776			—		(203,533		)	16,757			—
Other	—			—		(33		)	(79		)	(112		)
Net cash provided by financing activities	28,396			—		123,397			3,792			155,585
Net (decrease) increase in cash and cash equivalents	(6,073		)	—		(5,210		)	33			(11,250		)
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	23,042		$	—	$	4,547		$	2,464		$	30,053

	Six Months Ended September 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	$	(31,541	)	$	—	$	(12,751	)	$	(12,107	)	$	(56,399	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(158,333		)	(1,347		)	(159,680		)
Purchases of pipeline capacity allocations	—			—		(41,953		)	—			(41,953		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—		(113,297		)	—			(113,297		)
Cash flows from commodity derivatives	—			—		(25,015		)	—			(25,015		)
Proceeds from sales of assets	—			—		379			17			396
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Distributions of capital from unconsolidated entities	—			—		5,233			—			5,233
Payments on loan for natural gas liquids facility	—			—		4,324			—			4,324
Loan to affiliate	—			—		(1,700		)	—			(1,700		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash used in investing activities	—			—		(234,212		)	(1,330		)	(235,542		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		770,000			—			770,000
Payments on revolving credit facilities	—			—		(595,500		)	—			(595,500		)
Repurchases of senior notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(4,080		)	(343		)	(4,423		)
Debt issuance costs	(255		)	—		(65		)	—			(320		)
Contributions from partners	(442		)	—		—			—			(442		)
Contributions from noncontrolling interest owners	—			—		—			966			966
Distributions to partners	(83,707		)	—		—			—			(83,707		)
Distributions to noncontrolling interest owners	—			—		—			(2,750		)	(2,750		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018			—		—			—			235,018
Proceeds from sale of common units, net of offering costs	9,383			—		—			—			9,383
Payments for the early extinguishment of liabilities	—			—		(25,884		)	—			(25,884		)
Net changes in advances with consolidated entities	(128,960		)	—		113,907			15,053			—
Other	—			—		(20		)	—			(20		)
Net cash provided by financing activities	15,908			—		258,358			12,926			287,192
Net (decrease) increase in cash and cash equivalents	(15,633		)	—		11,395			(511		)	(4,749		)
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	10,116		$	—	$	12,179		$	1,132		$	23,427

XML

Organization and Operations (Details)	Sep. 30, 2016 state pipeline terminal
Crude oil logistics
Organization and operations
Number of crude oil pipelines | pipeline	2
Liquids
Organization and operations
Number of owned terminals | terminal	18
Retail propane
Organization and operations
Number of states in which entity operates | state	27

XML

Significant Accounting Policies - Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues [Abstract]
Amortization of contract liabilities to revenues	$ 1.2	$ 1.5	$ 2.5	$ 2.9

XML

Significant Accounting Policies - Supplemental Cash Flow (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Value of common units issued in business combinations	$ 3,969	$ 0	$ 3,969	$ 11,367
Supplemental Cash Flow Information
Cash interest paid	29,711	26,323	58,869	57,495
Income taxes paid (net of income tax refunds)	$ 71	$ 533	$ 1,755	$ 4,616

XML

Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Mar. 31, 2016
Inventories
Crude oil	$ 86,495	$ 84,030
Natural gas liquids:
Propane	73,704	28,639
Butane	44,929	8,461
Other	5,936	6,011
Refined products:
Gasoline	126,821	80,569
Diesel	138,245	99,398
Renewables	34,328	52,458
Other	9,882	8,240
Total	$ 520,340	$ 367,806

XML

Significant Accounting Policies - Investments in Unconsolidated Entities (Details) - USD ($) $ in Thousands	Apr. 01, 2016	Sep. 30, 2016	Jun. 03, 2016	Mar. 31, 2016
Investments in Unconsolidated Entities
Carrying Value		$ 190,662		$ 219,550
Water supply company
Investments in Unconsolidated Entities
Ownership interest				35.00%
Ownership interest acquired			65.00%
Glass Mountain
Investments in Unconsolidated Entities
Fair value in excess of historical net book value		$ 73,600
TLP
Investments in Unconsolidated Entities
Proceeds from sale of equity method investments	$ 112,400
Gain on disposal	$ 104,100
Crude oil logistics | Operating segment | Glass Mountain
Investments in Unconsolidated Entities
Ownership interest		50.00%
Carrying Value		$ 174,364		$ 179,594
Refined products and renewables | Operating segment | Ethanol production facility
Investments in Unconsolidated Entities
Ownership interest		19.00%
Carrying Value		$ 13,507		12,570
Refined products and renewables | Operating segment | TLP
Investments in Unconsolidated Entities
Ownership interest		0.00%
Carrying Value		$ 0		8,301
Water solutions | Operating segment | Water treatment and disposal facility
Investments in Unconsolidated Entities
Ownership interest		50.00%
Carrying Value		$ 2,235		2,238
Water solutions | Operating segment | Water supply company
Investments in Unconsolidated Entities
Ownership interest		100.00%
Carrying Value		$ 0		15,875
Retail propane | Operating segment | Retail propane company
Investments in Unconsolidated Entities
Ownership interest		50.00%
Carrying Value		$ 556		$ 972

XML

Significant Accounting Policies - Other Noncurrent Assets (Details) $ in Thousands	Sep. 30, 2016 USD ($) bbl	Mar. 31, 2016 USD ($) bbl
Other Assets, Noncurrent [Abstract]
Loan receivable	$ 44,957	$ 49,827
Tank bottoms	42,044	42,044
Line fill	35,013	35,060
Other	95,725	49,108
Total	$ 217,739	$ 176,039
Number of barrels of refined product | bbl	366,212	366,212
Number of barrels of crude oil | bbl	486,473	487,104

XML

Significant Accounting Policies - Accrued Expenses and Other Payables (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Mar. 31, 2016
Accounting Policies [Abstract]
Accrued compensation and benefits	$ 19,322	$ 40,517
Excise and other tax liabilities	56,147	59,455
Derivative liabilities	31,959	28,612
Accrued interest	19,594	20,543
Product exchange liabilities	7,045	5,843
Deferred gain on sale of general partner interest in TLP	30,113	30,113
Other	20,454	29,343
Total	$ 184,634	$ 214,426

XML

Significant Accounting Policies Significant Accounting Policies - Sale of General Partner Interest in TLP (Details) - USD ($) $ in Thousands		3 Months Ended	6 Months Ended
	Feb. 01, 2016	Sep. 30, 2016	Sep. 30, 2016	Mar. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred gain on sale of general partner interest in TLP		$ 30,113	$ 30,113	$ 30,113
General Partner Interest in TLP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred gain on disposal, amortization period	7 years
Recognized gain		7,600	15,100
General Partner Interest in TLP | Accrued expenses and other payables
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred gain on sale of general partner interest in TLP		30,100	30,100
General Partner Interest in TLP | Other noncurrent liabilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred gain on sale of general partner interest in TLP, noncurrent		$ 154,400	$ 154,400

XML

Income (Loss) Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2016
Income (Loss) Per Common Unit
Net (loss) income	$ (66,658)	$ (6,100)	$ 116,095	$ (31,107)
Less: Net loss (income) attributable to noncontrolling interests	59	(3,497)	(5,774)	(7,847)
Net (loss) income attributable to NGL Energy Partners LP	(66,599)	(9,597)	110,321	(38,954)
Less: Distributions to preferred unitholders	(8,668)	0	(12,052)	0
Less: Net loss (income) allocated to general partner	45	(16,185)	(158)	(31,559)
Net (loss) income allocated to common unitholders	$ (75,222)	$ (25,782)	$ 98,111	$ (70,513)
Basic (loss) income per common unit (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.93	$ (0.67)
Diluted (loss) income per common unit (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.91	$ (0.67)
Basic weighted average common units outstanding (in units)	106,186,389	105,189,463	105,183,556	104,542,427
Diluted weighted average common units outstanding (in units)	106,186,389	105,189,463	107,997,549	104,542,427
Class A Convertible Preferred Units
Income (Loss) Per Common Unit
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, units issued (in units)	19,942,169		19,942,169		0
Common units
Income (Loss) Per Common Unit
Basic (loss) income per common unit (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.93	$ (0.67)
Diluted (loss) income per common unit (in dollars per unit)	$ (0.71)	$ (0.25)	$ 0.91	$ (0.67)
Basic weighted average common units outstanding (in units)	106,186,389	105,189,463	105,183,556	104,542,427
Diluted weighted average common units outstanding (in units)	106,186,389	105,189,463	107,997,549	104,542,427
Common units | Warrant
Income (Loss) Per Common Unit
Weighted average number diluted shares outstanding adjustment (in units)			2,803,436
Performance awards | Common units
Income (Loss) Per Common Unit
Weighted average number diluted shares outstanding adjustment (in units)			10,621

XML

Acquisitions - Water Solutions Facilities (Details) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016 USD ($)	Sep. 30, 2016 USD ($) facility	Mar. 31, 2016 USD ($) business facility
Business Acquisition [Line Items]
Goodwill		$ 1,467,955	$ 1,315,362
Water Solutions Acquisitions 2017 Acquisitions
Business Acquisition [Line Items]
Number of businesses acquired | facility		3
Cash paid		$ 26,900
Contingent consideration liability		2,600
Property, plant and equipment		15,021
Goodwill		18,933
Intangible assets		3,878
Accrued expenses and other payables		(1,239)
Other noncurrent liabilities		(9,697)
Fair value of net assets acquired		26,896
Accrued royalties		8,200
Water Solutions Facilities2016 Acquisitions Accounting Completed
Business Acquisition [Line Items]
Business combination number for which acquisition accounting is completed | facility			9
Adjustment, property, plant, and equipment	$ 700
Adjustment accrued expenses and other payables	$ 1,000
Retail propane 2016 acquisitions
Business Acquisition [Line Items]
Number of businesses acquired | business			5
Adjustment accrued expenses and other payables		300
Water solutions
Business Acquisition [Line Items]
Goodwill		$ 434,091	$ 290,915

XML

Acquisitions Acquisitions - Acquisition of Remaining Interest in Water Solutions Facilities (Details) - Water Solutions Facility 2017 Acquisitions $ in Millions	Sep. 15, 2016 USD ($) facility
Business Acquisition [Line Items]
Ownership interest acquired	25.00%
Number of businesses acquired | facility	3
Cash paid	$ 10.0
Additional interest acquired	$ 7.4

XML

Acquisitions - Water Pipeline Company (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Sep. 30, 2016	Jun. 03, 2016	Jan. 07, 2016
Business Acquisition [Line Items]
Adjustment, other noncurrent liabilities		$ 406
Water Pipeline Company
Business Acquisition [Line Items]
Ownership interest acquired			24.50%	57.125%
Additional interest acquired			$ 5,200
Water Pipeline Company | Rights-of-way
Business Acquisition [Line Items]
Intangible assets	$ 1,100
Water Solutions Facilities2016 Acquisitions Accounting Completed
Business Acquisition [Line Items]
Adjustment, property, plant, and equipment	$ 700
Adjustment, other noncurrent liabilities		$ 300

XML

Acquisitions - Water Supply Company (Details) - Water supply company - USD ($) $ in Thousands	Jun. 03, 2016	Sep. 30, 2016	Mar. 31, 2016
Business Acquisition [Line Items]
Ownership interest acquired	65.00%
Cash paid	$ 1,000
Ownership interest			35.00%
Fair value of equity method investment	800
Revaluation of investments excluding bargain purchase	(14,900)
Bargain purchase	$ 600
Current assets		$ 1,713
Property, plant and equipment		8,874
Intangible assets		14,472
Current liabilities		(2,765)
Notes payable-intercompany		(19,900)
Fair value of net assets acquired		$ 2,394

XML

Acquisitions - Retail Propane Businesses (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) facility shares	Mar. 31, 2016 USD ($) business
Business Acquisition [Line Items]
General partners' capital account, units issued (in units) | shares	524
Common units issued, net of offering costs	$ 9,383
Goodwill	$ 1,467,955	$ 1,315,362
Retail propane 2017 acquisitions
Business Acquisition [Line Items]
Number of businesses acquired | facility	3
Cash paid	$ 72,100
Number of units issued | shares	218,617
Equity issued	$ 4,000
General partners' capital account, units issued (in units) | shares	219
Current assets	$ 6,282
Property, plant and equipment	30,576
Goodwill	9,419
Intangible assets	36,950
Accrued expenses and other payables	(5,555)
Advance payments received from customers	(1,587)
Fair value of net assets acquired	76,085
Retail propane 2016 acquisitions
Business Acquisition [Line Items]
Number of businesses acquired | business		5
Adjustment accrued expenses and other payables	300
Minimum | Retail propane 2017 acquisitions
Business Acquisition [Line Items]
Common units issued, net of offering costs	$ 100

XML

Acquisitions - Delaware Basin Water Solutions Facilities (Details) - Delaware Basin Water Solutions Facilities	Aug. 24, 2015 facility
Business Acquisition [Line Items]
Number of businesses acquired	4
Ownership interest acquired	50.00%

XML

Property, Plant and Equipment (Details) bbl in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016 USD ($) bbl	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) bbl	Sep. 30, 2015 USD ($)	Mar. 31, 2016 USD ($) bbl
Property, Plant and Equipment
Property, plant and equipment, gross	$ 2,079,780		$ 2,079,780		$ 1,916,063
Accumulated depreciation	(324,364)		(324,364)		(266,491)
Net property, plant and equipment	1,755,416		1,755,416		1,649,572
Depreciation expense	28,703	$ 34,469	56,357	$ 70,264
Capitalized interest expense	1,069	549	4,804	690
Operating segment | Loss on disposal or impairment of assets, net
Property, Plant and Equipment
Loss on disposal of assets	8,500	$ 1,100	10,800	$ 1,700
Natural gas liquids terminal and storage assets
Property, Plant and Equipment
Property, plant and equipment, gross	168,754		$ 168,754		169,758
Natural gas liquids terminal and storage assets | Minimum
Property, Plant and Equipment
Useful life			2 years
Natural gas liquids terminal and storage assets | Maximum
Property, Plant and Equipment
Useful life			30 years
Refined products terminal assets and equipment
Property, Plant and Equipment
Useful life			20 years
Property, plant and equipment, gross	6,844		$ 6,844		6,844
Retail propane equipment
Property, Plant and Equipment
Property, plant and equipment, gross	227,442		$ 227,442		201,312
Retail propane equipment | Minimum
Property, Plant and Equipment
Useful life			2 years
Retail propane equipment | Maximum
Property, Plant and Equipment
Useful life			30 years
Vehicles and railcars
Property, Plant and Equipment
Property, plant and equipment, gross	194,291		$ 194,291		185,547
Vehicles and railcars | Minimum
Property, Plant and Equipment
Useful life			3 years
Vehicles and railcars | Maximum
Property, Plant and Equipment
Useful life			25 years
Water treatment facilities and equipment
Property, Plant and Equipment
Property, plant and equipment, gross	535,255		$ 535,255		508,239
Water treatment facilities and equipment | Minimum
Property, Plant and Equipment
Useful life			3 years
Water treatment facilities and equipment | Maximum
Property, Plant and Equipment
Useful life			30 years
Crude oil tanks and related equipment
Property, Plant and Equipment
Property, plant and equipment, gross	140,245		$ 140,245		137,894
Crude oil tanks and related equipment | Minimum
Property, Plant and Equipment
Useful life			2 years
Crude oil tanks and related equipment | Maximum
Property, Plant and Equipment
Useful life			40 years
Barges and towboats
Property, Plant and Equipment
Property, plant and equipment, gross	89,973		$ 89,973		86,731
Barges and towboats | Minimum
Property, Plant and Equipment
Useful life			5 years
Barges and towboats | Maximum
Property, Plant and Equipment
Useful life			40 years
Information technology equipment
Property, Plant and Equipment
Property, plant and equipment, gross	42,218		$ 42,218		38,653
Information technology equipment | Minimum
Property, Plant and Equipment
Useful life			3 years
Information technology equipment | Maximum
Property, Plant and Equipment
Useful life			7 years
Buildings And Leasehold Improvements
Property, Plant and Equipment
Property, plant and equipment, gross	123,005		$ 123,005		118,885
Buildings And Leasehold Improvements | Minimum
Property, Plant and Equipment
Useful life			3 years
Buildings And Leasehold Improvements | Maximum
Property, Plant and Equipment
Useful life			40 years
Land
Property, Plant and Equipment
Property, plant and equipment, gross	50,132		$ 50,132		47,114
Tank bottoms
Property, Plant and Equipment
Property, plant and equipment, gross	20,105		20,105		20,355
Tank bottoms | Crude oil
Property, Plant and Equipment
Property, plant and equipment, gross	$ 19,120		$ 19,120		$ 19,348
Volume of property, plant and equipment | bbl	229		229		231
Tank bottoms | Other
Property, Plant and Equipment
Property, plant and equipment, gross	$ 985		$ 985		$ 1,007
Volume of property, plant and equipment | bbl	24		24		24
Other Machinery and Equipment
Property, Plant and Equipment
Property, plant and equipment, gross	$ 56,450		$ 56,450		$ 11,699
Other Machinery and Equipment | Minimum
Property, Plant and Equipment
Useful life			3 years
Other Machinery and Equipment | Maximum
Property, Plant and Equipment
Useful life			30 years
Construction in progress
Property, Plant and Equipment
Property, plant and equipment, gross	$ 425,066		$ 425,066		$ 383,032

XML

Goodwill (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2016
Goodwill
Goodwill at the beginning of the period	$ 1,315,362		$ 1,315,362
Revisions to acquisition accounting (Note 4)			(421)
Acquisitions (Note 4)			28,352
Adjustment to initial impairment estimate			124,662
Goodwill at the end of the period		$ 1,315,362	1,467,955
Crude oil logistics
Goodwill
Goodwill at the beginning of the period	579,846		579,846
Goodwill at the end of the period		579,846	579,846
Water solutions
Goodwill
Goodwill at the beginning of the period	290,915		290,915
Revisions to acquisition accounting (Note 4)			(419)
Acquisitions (Note 4)			18,933
Adjustment to initial impairment estimate	124,700		124,662
Goodwill at the end of the period		290,915	434,091
Goodwill impairment charge		380,200
Liquids
Goodwill
Goodwill at the beginning of the period	266,046		266,046
Goodwill at the end of the period		266,046	266,046
Retail propane
Goodwill
Goodwill at the beginning of the period	127,428		127,428
Revisions to acquisition accounting (Note 4)			(2)
Acquisitions (Note 4)			9,419
Goodwill at the end of the period		127,428	136,845
Refined products and renewables
Goodwill
Goodwill at the beginning of the period	$ 51,127		51,127
Goodwill at the end of the period		$ 51,127	51,127
Water Solutions Acquisitions 2017 Acquisitions
Goodwill
Goodwill at the end of the period			18,933
Retail propane 2017 acquisitions
Goodwill
Goodwill at the end of the period			$ 9,419

XML

Intangible Assets (Details) - USD ($) $ in Thousands		6 Months Ended
	Jun. 03, 2016	Sep. 30, 2016	Mar. 31, 2016
Amortizable
Gross Carrying Amount		$ 1,155,398	$ 1,085,958
Accumulated Amortization		356,314	316,878
Finite-Lived Intangible Assets, Net		799,084	769,080
INTANGIBLE ASSETS, net of accumulated amortization		1,190,147	1,148,890
Non-Amortizable
Total non-amortizable		391,063	379,810
Gross carrying amount of intangible assets		$ 1,546,461	1,465,768
Weighted average remaining amortization period		8 years 7 months 12 days
Water solutions
Amortizable
Amortizable life	2 years
Customer commitments
Non-Amortizable
Total non-amortizable		$ 310,000	310,000
Right-of-way and easements
Non-Amortizable
Total non-amortizable		47,721	47,190
Water rights
Non-Amortizable
Total non-amortizable		14,472	0
Trade names
Non-Amortizable
Total non-amortizable		18,870	22,620
Trade names | Operating segment | Water solutions
Non-Amortizable
Write off of intangible asset		5,200
Customer relationships
Amortizable
Gross Carrying Amount		883,896	852,118
Accumulated Amortization		274,111	233,838
Finite-Lived Intangible Assets, Net		$ 609,785	618,280
Customer relationships | Minimum
Amortizable
Amortizable life		3 years
Customer relationships | Maximum
Amortizable
Amortizable life		20 years
Pipeline capacity rights
Amortizable
Amortizable life		30 years
Gross Carrying Amount		$ 161,589	119,636
Accumulated Amortization		8,957	6,559
Finite-Lived Intangible Assets, Net		$ 152,632	113,077
Water facility development agreement
Amortizable
Amortizable life		5 years
Gross Carrying Amount		$ 0	14,000
Accumulated Amortization		0	7,700
Finite-Lived Intangible Assets, Net		0	6,300
Water facility development agreement | Operating segment | Water solutions
Non-Amortizable
Write off of intangible asset	$ 5,800
Executory contracts and other agreements
Amortizable
Gross Carrying Amount		22,713	23,920
Accumulated Amortization		19,699	21,075
Finite-Lived Intangible Assets, Net		$ 3,014	2,845
Executory contracts and other agreements | Minimum
Amortizable
Amortizable life		2 years
Executory contracts and other agreements | Maximum
Amortizable
Amortizable life		30 years
Non-compete agreements
Amortizable
Gross Carrying Amount		$ 31,784	20,903
Accumulated Amortization		15,101	13,564
Finite-Lived Intangible Assets, Net		$ 16,683	7,339
Non-compete agreements | Minimum
Amortizable
Amortizable life		2 years
Non-compete agreements | Maximum
Amortizable
Amortizable life		32 years
Trade names
Amortizable
Gross Carrying Amount		$ 15,439	15,439
Accumulated Amortization		12,882	12,034
Finite-Lived Intangible Assets, Net		$ 2,557	3,405
Trade names | Minimum
Amortizable
Amortizable life		1 year
Trade names | Maximum
Amortizable
Amortizable life		10 years
Debt issuance costs
Amortizable
Amortizable life		3 years
Gross Carrying Amount		$ 39,977	39,942
Accumulated Amortization		25,564	22,108
Finite-Lived Intangible Assets, Net		$ 14,413	$ 17,834

XML

Intangible Assets - Amortization (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2016
Amortization related to intangible assets
Amortization expense	$ 25,380	$ 25,461	$ 49,953	$ 52,683
Future amortization expense of intangible assets
2017 (six months)	51,028		51,028
2018	98,717		98,717
2019	89,701		89,701
2020	82,185		82,185
2021	69,422		69,422
Thereafter	408,031		408,031
Total	799,084		799,084		$ 769,080
Depreciation and amortization
Amortization related to intangible assets
Amortization expense	21,900	22,291	43,152	46,328
Cost of sales
Amortization related to intangible assets
Amortization expense	1,749	1,700	3,345	3,401
Interest expense
Amortization related to intangible assets
Amortization expense	$ 1,731	$ 1,470	$ 3,456	$ 2,954

XML

Long-Term Debt (Details) $ in Thousands	1 Months Ended	3 Months Ended			6 Months Ended
	Oct. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Mar. 31, 2016 USD ($)	Jul. 09, 2014 USD ($)	Oct. 16, 2013 USD ($)	Jun. 19, 2012 USD ($)
Long-Term Debt
Face amount		$ 3,084,536			$ 3,084,536		$ 2,936,244
Face amount, current portion		8,046			8,046		7,907
Face amount, long-term		3,076,490			3,076,490		2,928,337
Unamortized debt issuance costs		(13,482)			(13,482)		(15,500)
Book value		3,071,054			3,071,054		2,920,744
Book value, current		8,046			8,046		7,907
LONG-TERM DEBT, net of debt issuance costs and current maturities		3,063,008			3,063,008		2,912,837
Amortization of debt issuance costs		1,000		$ 800	1,800	$ 1,600
Repurchases of senior notes					15,129	$ 0
Expected Future Amortization of Debt Issuance Costs [Abstract]
2017 (six months)		1,619			1,619
2018		3,229			3,229
2019		3,226			3,226
2020		2,236			2,236
2021		1,827			1,827
Thereafter		1,345			1,345
Total		13,482			13,482
Revolving Credit Facility
Long-Term Debt
Long-term line of credit		$ 2,000,000			$ 2,000,000
Interest rate		2.83%			2.83%
Revolving Credit Facility
Long-Term Debt
Maximum borrowing capacity		$ 2,484,000			$ 2,484,000
Increased borrowing capacity with the exercise of accordion feature		150,000			$ 150,000
Actual leverage ratio					4.15
Actual interest coverage ratio					4.60
Revolving Credit Facility | Minimum
Long-Term Debt
Commitments fees charged on unused capacity					0.38%
Interest coverage ratio					2.75
Revolving Credit Facility | Maximum
Long-Term Debt
Commitments fees charged on unused capacity					0.50%
Leverage ratio					4.75
Revolving Credit Facility | Alternate base rate | Minimum
Long-Term Debt
Interest rate margin added to variable rate base					0.50%
Revolving Credit Facility | Alternate base rate | Maximum
Long-Term Debt
Interest rate margin added to variable rate base					1.75%
Revolving Credit Facility | LIBOR option
Long-Term Debt
Interest rate margin added to variable rate base					2.25%
Reference rate					0.53%
Revolving Credit Facility | LIBOR option | Minimum
Long-Term Debt
Interest rate margin added to variable rate base					1.50%
Revolving Credit Facility | LIBOR option | Maximum
Long-Term Debt
Interest rate margin added to variable rate base					2.75%
Revolving Credit Facility | Prime Rate
Long-Term Debt
Interest rate margin added to variable rate base					1.25%
Reference rate					3.50%
Revolving Credit Facility | Expansion Capital Facility
Long-Term Debt
Face amount		1,312,000			$ 1,312,000		1,229,500
Unamortized debt issuance costs		0			0		0
Book value		1,312,000			1,312,000		1,229,500
Long-term line of credit		1,446,000			1,446,000
Revolving Credit Facility | Working Capital Facility
Long-Term Debt
Face amount		710,500			710,500		618,500
Unamortized debt issuance costs		0			0		0
Book value		710,500			710,500		618,500
Maximum borrowing capacity		1,038,000			1,038,000
Outstanding letters of credit		$ 75,300			$ 75,300
Revolving Credit Facility | Letters of credit
Long-Term Debt
Fixed interest rate		2.25%			2.25%
5.125% Senior Notes due 2019
Long-Term Debt
Face amount		$ 383,467			$ 383,467		388,467
Fixed interest rate		5.125%			5.125%			5.125%
Unamortized debt issuance costs		$ (3,871)			$ (3,871)		(4,681)
Book value		379,596			379,596		383,786
Debt issued								$ 400,000
Repurchase amount		5,000			5,000
Repurchases of senior notes		3,100
Gain on early extinguishment of debt		1,800
Write off of debt issuance cost		100
6.875% Senior Notes due 2021
Long-Term Debt
Face amount		$ 369,063			$ 369,063		388,289
Fixed interest rate		6.875%			6.875%				6.875%
Unamortized debt issuance costs		$ (6,433)			$ (6,433)		(7,545)
Book value		362,630			362,630		380,744
Debt issued									$ 450,000
Repurchase amount			$ 19,200
Repurchases of senior notes (excluding payments of accrued interest)			12,000
Gain on early extinguishment of debt			6,800
Write off of debt issuance cost			$ 400
6.650% Senior Notes due 2022
Long-Term Debt
Face amount		$ 250,000			$ 250,000		250,000
Fixed interest rate		6.65%			6.65%					6.65%
Unamortized debt issuance costs		$ (3,055)			$ (3,055)		(3,166)
Book value		246,945			246,945		246,834
Debt issued										$ 250,000
Repayments in semi-annual installments					25,000
7.50% Senior Notes due 2023 | Subsequent Event
Long-Term Debt
Fixed interest rate	7.50%
Debt issued	$ 700,000
Proceeds from unsecured notes payable	$ 688,000
Other long-term debt
Long-Term Debt
Face amount		59,506			59,506		61,488
Unamortized debt issuance costs		(123)			(123)		(108)
Book value		$ 59,383			$ 59,383		$ 61,380
Other long-term debt | Minimum
Long-Term Debt
Fixed interest rate		1.17%			1.17%
Other long-term debt | Maximum
Long-Term Debt
Fixed interest rate		7.08%			7.08%

XML

Long-Term Debt - Maturity Schedule (Details) $ in Thousands	Sep. 30, 2016 USD ($)
Maturities
2017 (six months)	$ 3,405
2018	33,014
2019	2,079,357
2020	439,839
2021	84,728
Thereafter	444,193
Total	3,084,536
Revolving Credit Facility
Maturities
2019	2,022,500
Total	2,022,500
5.125% Senior Notes due 2019
Maturities
2020	383,467
Total	383,467
6.875% Senior Notes due 2021
Maturities
Thereafter	369,063
Total	369,063
6.650% Senior Notes due 2022
Maturities
2018	25,000
2019	50,000
2020	50,000
2021	50,000
Thereafter	75,000
Total	250,000
Other long-term debt
Maturities
2017 (six months)	3,405
2018	8,014
2019	6,857
2020	6,372
2021	34,728
Thereafter	130
Total	$ 59,506

XML

Income Taxes (Details)	6 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Minimum percentage of qualifying income of non taxable subsidiaries	90.00%

XML

Commitments and Contingencies - Environmental Matters (Details) $ in Millions	Sep. 30, 2016 USD ($)
Environmental matter
Environmental matters liability	$ 2.2

XML

Commitments and Contingencies - Asset Retirement Obligations (Details) $ in Thousands	6 Months Ended
	Sep. 30, 2016 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 5,574
Liabilities incurred	406
Accretion expense	207
Balance at end of period	$ 6,187

XML

Commitments and Contingencies - Operating Leases (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Future minimum lease payments
2017 (six months)	$ 67,837		$ 67,837
2018	122,935		122,935
2019	101,047		101,047
2020	90,112		90,112
2021	80,457		80,457
Thereafter	135,486		135,486
Total	597,874		597,874
Rental expense	$ 27,000	$ 33,300	$ 56,900	$ 67,100

XML

Commitments and Contingencies - Pipeline Capacity Agreements (Details) - Pipeline Capacity Agreements $ in Thousands	Sep. 30, 2016 USD ($)
Future minimum throughput payments
2017 (six months)	$ 26,008
2018	52,082
2019	52,170
2020	42,418
Total	$ 172,678

XML

Commitments and Contingencies - Sales and Purchase Contracts (Details) gal in Thousands, bbl in Thousands, $ in Thousands	Sep. 30, 2016 USD ($) bbl gal
Prepaid expenses and other current assets
Sales and purchase contracts for natural gas liquids and crude oil
Net asset (liability)	$ 41,000
Accrued expenses and other payables
Sales and purchase contracts for natural gas liquids and crude oil
Net asset (liability)	$ 29,600
Natural gas liquids
Sales and purchase contracts for natural gas liquids and crude oil
Fixed-price purchase commitments (in gallons/barrels) | gal	35,592
Index-price purchase commitments (in gallons/barrels) | gal	587,044
Fixed-price sale commitments (in gallons/barrels) | gal	163,546
Index-price sale commitments (in gallons/barrels) | gal	414,042
Fixed-price purchase commitments	$ 18,710
Index-price purchase commitments	347,020
Fixed-price sale commitments	105,868
Index-price sale commitments	$ 317,983
Crude oil
Sales and purchase contracts for natural gas liquids and crude oil
Fixed-price purchase commitments (in gallons/barrels) | bbl	1,993
Index-price purchase commitments (in gallons/barrels) | bbl	14,466
Fixed-price sale commitments (in gallons/barrels) | bbl	3,415
Index-price sale commitments (in gallons/barrels) | bbl	12,953
Fixed-price purchase commitments	$ 88,079
Index-price purchase commitments	655,273
Fixed-price sale commitments	152,584
Index-price sale commitments	$ 637,731

XML

Equity - Partnership Equity (Details)	3 Months Ended	6 Months Ended
	Mar. 31, 2016	Sep. 30, 2016
Equity
General partner interest	0.10%	0.10%
Limited partner interest	99.90%	99.90%
Common units
Equity
General partner interest		0.10%
Limited partner interest		99.90%

XML

Equity - Distribution Policy (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 14, 2016	Oct. 20, 2016	Aug. 12, 2016	Jul. 22, 2016	May 13, 2016	Apr. 21, 2016
Partners Capital Accounts [Line Items]
Amount Per Unit (in dollars per share)				$ 0.390000		$ 0.390000
Amount Paid/Payable to Limited Partners			$ 41,146		$ 40,626
Amount Paid/Payable to General Partner			$ 71		$ 70
Subsequent Event
Partners Capital Accounts [Line Items]
Amount Per Unit (in dollars per share)		$ 0.390000
Amount Paid/Payable to Limited Partners	$ 41,907
Amount Paid/Payable to General Partner	$ 72

XML

Equity - Class A Convertible Preferred Units (Details) - USD ($)					3 Months Ended	6 Months Ended
	Oct. 20, 2016	Jun. 24, 2016	May 11, 2016	Apr. 21, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Jul. 22, 2016	Jun. 23, 2016
Equity-Based Incentive Compensation
Proceeds from issuance of preferred units		$ 140,000,000	$ 100,000,000
Preferred units, issued (in units)		11,632,932	8,309,237
Outstanding (in units)		2,552,149	1,822,963		4,375,112	4,375,112
Exercise price (in dollars per unit)		$ 0.01
Proceeds from sale of convertible preferred units and warrants, net of offering costs						$ 235,018,000	$ 0
Oaktree Capital Management L.P.
Equity-Based Incentive Compensation
Authorized amount				$ 200,000,000					$ 240,000,000
Oaktree Capital Management L.P. | Class A Convertible Preferred Units
Equity-Based Incentive Compensation
Stated interest rate				10.75%
Days after quarter end distribution paid				45 days
Dividends declared, amount								$ 1,800,000
Initial conversion price (in dollars per unit)				$ 12.035
Reset conversion price, trading days used for adjustment				15 days
Reset conversion price (in dollars per unit)				$ 5
Number of days within closing date of registration statement required to file within				180 days
Number of days after closing date registration statement declared effective				360 days
Class of warrant or right, term				8 years
Proceeds from sale of convertible preferred units and warrants, net of offering costs				$ 235,000,000
Payments of stock issuance costs				5,000,000
Proceeds from sale of convertible preferred units and warrants, net of offering costs				186,400,000
Allocation of value to beneficial conversion feature of Class A convertible preferred units				$ 131,500,000
Conversion period				3 years
Accretion of beneficial conversion					$ 2,200,000	$ 3,800,000
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Warrant
Equity-Based Incentive Compensation
Proceeds from sale of convertible preferred units and warrants, net of offering costs				$ 48,600,000
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | From and after the first anniversary of the original issue date
Equity-Based Incentive Compensation
Percentage convertible				33.33%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | From and after the second anniversary of the original issue date
Equity-Based Incentive Compensation
Percentage convertible				33.33%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | From and after the third anniversary of the original issue date
Equity-Based Incentive Compensation
Percentage convertible				33.33%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after first, but prior to the second anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.40
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after the second, but prior to the third anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.15
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after the third, but prior to the eighth anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.10
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after the eighth anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.01
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Prior to the first anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.40
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after the first but prior to the second anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.30
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | On or after the second anniversary of the closing date
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.20
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Thereafter
Equity-Based Incentive Compensation
Preferred stock redemption premium percentage				1.01
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | First 60 day period following the effectiveness deadline
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.25%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Each subsequent 30 day period
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.25%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | 61-91 days
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.50%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | 91-120 days
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.75%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Thereafter
Equity-Based Incentive Compensation
Percentage increase in dividend rate				1.00%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | First six-month period
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.25%
Payment default period				6 months
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Second six-month period
Equity-Based Incentive Compensation
Percentage increase in dividend rate				0.25%
Payment default period				6 months
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Maximum
Equity-Based Incentive Compensation
Stated interest rate				11.25%
Oaktree Capital Management L.P. | Class A Convertible Preferred Units | Maximum | Thereafter
Equity-Based Incentive Compensation
Percentage increase in dividend rate				1.00%
Subsequent Event | Oaktree Capital Management L.P. | Class A Convertible Preferred Units
Equity-Based Incentive Compensation
Preferred units, distributions declared	$ 6,400,000

XML

Equity Equity - At-The-Market ("ATM") Offering (Details) - USD ($)		1 Months Ended	3 Months Ended		6 Months Ended
	Aug. 24, 2016	Nov. 07, 2016	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2016
Equity
Aggregate offering price	$ 200,000,000
Limited partners, common units issued (in units)			524,000
Proceeds from at the market program			$ 9,600,000
General partners' capital account, units issued (in units)			524		524
Common units issued, net of offering costs					$ 9,383,000
General partner interest				0.10%	0.10%
Aggregate offering price remaining for sale			$ 190,400,000
Common units
Equity
General partner interest					0.10%
Subsequent Event
Equity
Proceeds from at the market program		$ 3,700,000
Shares issued under the ATM Program		192,000
Minimum
Equity
Limited partners' offering costs (less than $0.1 million)			$ 100,000		$ 100,000
Minimum | Subsequent Event
Equity
Limited partners' offering costs (less than $0.1 million)		$ 100,000

XML

Equity - Award Activity (Details) - USD ($)	6 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Equity-Based Incentive Compensation
Equity	$ 1,955,314,000		$ 1,694,065,000
Award activity
Units granted (in units)	1,008,091
Restricted units
Equity-Based Incentive Compensation
Distributions on restricted units during the vesting period	$ 0
Service awards
Award activity
Unvested restricted units at the beginning of the period (in units)	2,297,132
Units granted (in units)	3,048,100
Units vested and issued (in units)	(2,340,082)
Units forfeited (in units)	(322,100)
Unvested restricted units at the end of the period (in units)	2,683,050
Service awards | Taxes withheld upon the vesting of restricted units
Equity-Based Incentive Compensation
Share-based arrangements liability reclassified to equity		$ (25,600,000)
Equity		25,600,000
Performance awards
Award activity
Unvested restricted units at the beginning of the period (in units)	637,382
Units granted (in units)	932,309
Units forfeited (in units)	(380,691)
Unvested restricted units at the end of the period (in units)	1,189,000
Performance awards | Taxes withheld upon the vesting of restricted units
Equity-Based Incentive Compensation
Share-based arrangements liability reclassified to equity		(1,800,000)
Equity		$ 1,800,000

XML

Equity - Service Awards Vesting Schedule (Details) - Service awards	6 Months Ended
	Sep. 30, 2016 shares
Equity-Based Incentive Compensation
Number of units scheduled to vest (in units)	2,340,082
Unvested restricted units at the beginning of the period (in units)	2,297,132
2017 (six months)
Equity-Based Incentive Compensation
Number of units scheduled to vest (in units)	10,000
2018
Equity-Based Incentive Compensation
Number of units scheduled to vest (in units)	887,350
2019
Equity-Based Incentive Compensation
Number of units scheduled to vest (in units)	894,800
Thereafter
Equity-Based Incentive Compensation
Number of units scheduled to vest (in units)	890,900

XML

Equity - Service Awards Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2016
Estimated equity-based compensation expense
Units granted (in units)			1,008,091
Accrued expenses related to bonuses granted in common units			$ 2,200		$ 16,800
Compensation cost			19,000
Service awards
Equity-Based Incentive Compensation
Expense recorded	$ 25,800	$ 14,900	46,700	$ 33,400
Estimated equity-based compensation expense
2017 (six months)			9,329
2018			12,239
2019			8,853
Thereafter			2,317
Total			$ 32,738
Units granted (in units)			3,048,100
Performance awards
Estimated equity-based compensation expense
2017 (six months)			$ 4,138
2018			6,197
2019			3,232
Thereafter			655
Total			$ 14,222
Units granted (in units)			932,309
Compensation cost	$ 1,600	$ 300	$ 3,100	$ 18,100

XML

Equity - Performance Awards (Details) - USD ($)	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jun. 30, 2016	Mar. 31, 2016
Equity-Based Incentive Compensation
Compensation cost			$ 19,000,000
Other disclosures
Maximum number of common units that may be delivered under the LTIP as a percentage of issued and outstanding common units			10.00%
Incremental amount that the maximum common units deliverable may automatically increase under the LTIP, expressed as a percentage of issued and outstanding common units			10.00%
Number of common units available for issuance under the LTIP (in units)	1,100,000		1,100,000
Performance awards
Equity-Based Incentive Compensation
Stock issued during period, shares, restricted stock award	1,189,000		1,189,000			637,382
Compensation cost	$ 1,600,000	$ 300,000	$ 3,100,000	$ 18,100,000
Estimated equity-based compensation expense
2017 (six months)			4,138,000
2018			6,197,000
2019			3,232,000
Thereafter			655,000
Total			$ 14,222,000
Performance awards | Less than 50%
Equity-Based Incentive Compensation
Percentage of entities outperformed, upper limit			50.00%
Percentage of awards to vest			0.00%
Performance awards | 50%-75% | Minimum
Equity-Based Incentive Compensation
Percentage of entities outperformed, lower limit			50.00%
Percentage of awards to vest			50.00%
Performance awards | 50%-75% | Maximum
Equity-Based Incentive Compensation
Percentage of entities outperformed, upper limit			75.00%
Percentage of awards to vest			100.00%
Performance awards | 75%-90% | Minimum
Equity-Based Incentive Compensation
Percentage of entities outperformed, lower limit			75.00%
Percentage of awards to vest			100.00%
Performance awards | 75%-90% | Maximum
Equity-Based Incentive Compensation
Percentage of entities outperformed, upper limit			90.00%
Percentage of awards to vest			200.00%
Performance awards | Greater than 90%
Equity-Based Incentive Compensation
Percentage of entities outperformed, lower limit			90.00%
Percentage of awards to vest			200.00%
Performance awards | July 1, 2016
Equity-Based Incentive Compensation
Fair value of unvested awards					$ 0

XML

Fair Value of Financial Instruments - Fair Value of Commodity Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Mar. 31, 2016
Prepaid expenses and other current assets
Derivative assets (liabilities)
Net (liability) asset	$ 41,000
Accrued expenses and other payables
Derivative assets (liabilities)
Net (liability) asset	29,600
Commodity contracts
Assets:
Derivative Assets	44,967	$ 80,061
Netting of counterparty contracts, assets	(3,091)	(3,384)
Net cash collateral provided (held)	21	(18,176)
Commodity derivatives in condensed consolidated balance sheet, assets	41,897	58,501
Liabilities:
Derivative Liabilities	(72,513)	(32,595)
Netting of counterparty contracts, liabilities	3,091	3,384
Cash collateral provided (held)	37,463	599
Commodity derivatives in condensed consolidated balance sheet, liabilities	(31,959)	(28,612)
Derivative assets (liabilities)
Net (liability) asset	9,938	29,889
Commodity contracts | Prepaid expenses and other current assets
Derivative assets (liabilities)
Net (liability) asset	41,897	58,501
Commodity contracts | Accrued expenses and other payables
Derivative assets (liabilities)
Net (liability) asset	(31,959)	(28,612)
Level 1 | Commodity contracts
Assets:
Derivative Assets	2,512	47,361
Liabilities:
Derivative Liabilities	(40,260)	(3,983)
Level 2 | Commodity contracts
Assets:
Derivative Assets	42,455	32,700
Liabilities:
Derivative Liabilities	$ (32,253)	$ (28,612)

XML

Fair Value of Financial Instruments - Derivative Contract Positions (Details) bbl in Thousands, $ in Thousands	Sep. 30, 2016 USD ($) bbl	Mar. 31, 2016 USD ($) bbl
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ (27,546)	$ 47,466
Net cash collateral provided (held)	37,484	(17,577)
Net commodity derivative asset in condensed consolidated balance sheet	9,938	29,889
Cross-commodity
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ 1,465	$ 1,663
Cross-commodity | Long
Derivative contract information
Total Notional Units (Barrels) | bbl	126	251
Crude oil fixed-price
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ (3,041)	$ (3,655)
Crude oil fixed-price | Short
Derivative contract information
Total Notional Units (Barrels) | bbl	588	1,583
Propane fixed-price
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ 518	$ (592)
Propane fixed-price | Long
Derivative contract information
Total Notional Units (Barrels) | bbl	462	540
Refined products fixed-price
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ (22,607)	$ 48,557
Refined products fixed-price | Short
Derivative contract information
Total Notional Units (Barrels) | bbl	5,628	5,355
Other
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ (3,881)	$ 1,493

XML

Fair Value of Financial Instruments - Gains (Losses) From Commodity Derivatives (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Net gains (losses) on derivatives	$ 14.7	$ 85.8	$ (45.0)	$ 44.5

XML

Fair Value of Financial Instruments - Interest Rate Risk (Details) - Revolving Credit Facility $ in Billions	Sep. 30, 2016 USD ($)
Interest Rate Risk
Outstanding debt	$ 2.0
Interest rate	2.83%

XML

Fair Value of Financial Instruments - Fair Value of Fixed-Rate Notes (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Jul. 09, 2014	Oct. 16, 2013	Jun. 19, 2012
5.125% Senior Notes due 2019
Fair Value of Fixed - Rate Notes
Fair value of fixed - rate notes	$ 360,459
Fixed interest rate	5.125%	5.125%
6.875% Senior Notes due 2021
Fair Value of Fixed - Rate Notes
Fair value of fixed - rate notes	$ 349,995
Fixed interest rate	6.875%		6.875%
6.650% Senior Notes due 2022
Fair Value of Fixed - Rate Notes
Fair value of fixed - rate notes	$ 253,838
Fixed interest rate	6.65%			6.65%

XML

Segments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2016
Segment information
Revenues	$ 3,045,538	$ 3,193,195	$ 5,767,508	$ 6,731,664
Corporate and Other	248	0	515	0
Depreciation and amortization	50,603	56,761	99,509	116,592
Operating income (loss)	(35,828)	18,298	158,072	17,088
Additions to property, plant and equipment and intangible assets	137,509	159,203	267,089	323,268
Long-lived assets, net	4,413,518		4,413,518		$ 4,113,824
Total assets	6,073,918		6,073,918		5,560,155
Operating segment | Crude oil logistics
Segment information
Revenues	349,885	1,007,578	775,836	2,335,362
Depreciation and amortization	9,025	10,053	17,993	20,055
Operating income (loss)	(19,039)	(75)	(19,664)	11,885
Additions to property, plant and equipment and intangible assets	32,397	44,384	104,702	107,023
Long-lived assets, net	1,720,278		1,720,278		1,679,027
Total assets	2,318,083		2,318,083		2,197,113
Operating segment | Crude oil logistics | Crude oil sales
Segment information
Revenues	341,981	997,106	756,600	2,309,889
Operating segment | Crude oil logistics | Crude oil transportation and other
Segment information
Revenues	9,172	12,746	22,106	31,695
Operating segment | Water solutions
Segment information
Revenues	39,733	47,494	75,486	101,787
Depreciation and amortization	25,129	22,416	49,563	43,262
Operating income (loss)	(4,430)	18,257	75,034	28,704
Additions to property, plant and equipment and intangible assets	25,237	72,531	68,353	133,020
Long-lived assets, net	1,316,196		1,316,196		1,162,405
Total assets	1,354,786		1,354,786		1,236,875
Operating segment | Water solutions | Service fees
Segment information
Revenues	28,528	35,203	54,225	71,941
Operating segment | Water solutions | Recovered hydrocarbons
Segment information
Revenues	5,681	10,746	12,877	26,564
Operating segment | Water solutions | Other revenues
Segment information
Revenues	5,524	1,545	8,384	3,282
Operating segment | Liquids
Segment information
Revenues	234,260	258,992	439,309	507,977
Depreciation and amortization	4,425	2,745	8,874	7,749
Operating income (loss)	8,384	20,370	8,327	19,899
Additions to property, plant and equipment and intangible assets	6,693	18,886	13,161	36,064
Long-lived assets, net	575,963		575,963		572,081
Total assets	785,303		785,303		693,872
Operating segment | Liquids | Other revenues
Segment information
Revenues	8,075	10,122	15,222	19,622
Operating segment | Liquids | Propane sales
Segment information
Revenues	101,613	98,770	198,084	204,260
Operating segment | Liquids | Other product sales
Segment information
Revenues	135,700	160,836	249,435	308,347
Operating segment | Retail propane
Segment information
Revenues	51,090	53,206	111,477	117,653
Depreciation and amortization	10,705	8,909	20,392	17,615
Operating income (loss)	(8,717)	(1,765)	(11,219)	(2,465)
Additions to property, plant and equipment and intangible assets	71,425	15,814	77,974	22,709
Long-lived assets, net	549,429		549,429		483,330
Total assets	611,340		611,340		538,267
Operating segment | Retail propane | Other revenues
Segment information
Revenues	9,331	9,409	17,638	17,724
Operating segment | Retail propane | Propane sales
Segment information
Revenues	36,170	36,119	77,811	79,304
Operating segment | Retail propane | Distillate sales
Segment information
Revenues	5,589	7,678	16,044	20,625
Operating segment | Refined products and renewables
Segment information
Revenues	2,370,322	1,825,925	4,364,885	3,668,885
Depreciation and amortization	416	11,152	833	25,327
Operating income (loss)	11,387	(5,244)	161,156	27,776
Additions to property, plant and equipment and intangible assets	1,143	7,588	1,167	23,283
Long-lived assets, net	219,157		219,157		180,783
Total assets	904,386		904,386		765,806
Operating segment | Refined products and renewables | Service fees
Segment information
Revenues	(121)	28,739	11,145	56,812
Operating segment | Refined products and renewables | Refined products sales
Segment information
Revenues	2,274,715	1,704,259	4,151,572	3,413,208
Operating segment | Refined products and renewables | Renewables sales
Segment information
Revenues	95,830	93,189	202,312	199,342
Operating segment | Corporate and other
Segment information
Depreciation and amortization	903	1,486	1,854	2,584
Operating income (loss)	(23,413)	(13,245)	(55,562)	(68,711)
Additions to property, plant and equipment and intangible assets	614	0	1,732	1,169
Long-lived assets, net	32,495		32,495		36,198
Total assets	100,020		100,020		$ 128,222
Elimination of intersegment sales | Crude oil logistics
Segment information
Revenues	(1,268)	(2,274)	(2,870)	(6,222)
Elimination of intersegment sales | Liquids
Segment information
Revenues	(11,128)	(10,736)	(23,432)	(24,252)
Elimination of intersegment sales | Retail propane
Segment information
Revenues	0	0	(16)	0
Elimination of intersegment sales | Refined products and renewables
Segment information
Revenues	$ (102)	$ (262)	$ (144)	$ (477)

XML

Transactions with Affiliates (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jun. 03, 2016	Mar. 31, 2016
Transactions with Affiliates
Accounts receivable-affiliates	$ 3,540			$ 3,540			$ 15,625
Accounts payable to affiliates	6,244			6,244			7,193
Water supply company
Transactions with Affiliates
Ownership interest acquired						65.00%
SemGroup
Transactions with Affiliates
Sales to related party	3,513		$ 4,593	3,584	$ 42,031
Purchases from related party	1,938		6,478	3,963	45,303
Accounts receivable-affiliates	3,401			3,401			1,166
Accounts payable to affiliates	4,015			4,015			1,823
Equity method investees
Transactions with Affiliates
Sales to related party	95		1,696	500	3,086
Purchases from related party	27,345		24,816	57,992	55,764
Accounts receivable-affiliates	0			0			14,446
Accounts payable to affiliates	1,155			1,155			3,947
Loan receivable from affiliates							22,300
Loan payment received from investee		$ 700
Impairment of loan receivable from investee		$ 1,700
Equity method investees | Loan Agreement
Transactions with Affiliates
Loan receivable from affiliates	1,700			$ 1,700
Loan agreement successive extension period				1 year
Entities affiliated with management
Transactions with Affiliates
Increase in property, plant and equipment				$ 10,500
Sales to related party	75		91	152	198
Purchases from related party	3,493		$ 16,214	11,736	$ 23,394
Accounts receivable-affiliates	139			139			13
Accounts payable to affiliates	$ 1,074			$ 1,074			$ 1,423

XML

Other Matters (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
	Jun. 03, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment information
Purchases of pipeline capacity allocations				$ 41,953	$ 0
Payment to terminate contract				16,875	0
Payments for the early extinguishment of liabilities				25,884	0
Gain on early extinguishment of liabilities		$ 938	$ 0	30,890	0
Loss on disposal or impairment of assets, net		$ (852)	$ (1,291)	203,467	$ (1,712)
Water solutions
Segment information
Payment to terminate contract	$ 49,600
Amortizable life	2 years
Increase in property, plant and equipment	$ 1,200
Intangible asset additions	3,300
Noncontrolling interest, increase from business combination	2,800
Payments for the early extinguishment of liabilities	25,500			46,800
Release of liabilities, contract termination	16,900
Gain on early extinguishment of liabilities				21,300
Loss on disposal or impairment of assets, net				$ 22,700
Water solutions | Accrued expenses and other payables
Segment information
Payment to terminate contract	$ 2,100

XML

Subsequent Events (Details) - 7.50% Senior Notes due 2023 - Subsequent Event $ in Millions	1 Months Ended
	Oct. 31, 2016 USD ($)
Subsequent events
Debt issued	$ 700.0
Proceeds from unsecured notes payable	688.0
Senior unsecured notes purchaser's discount	10.5
Senior notes offering costs	$ 1.5
Fixed interest rate	7.50%

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information - Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Mar. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 23,427	$ 28,176	$ 30,053	$ 41,303
Accounts receivable - trade, net of allowance for doubtful accounts	592,074	521,014
Accounts receivable-affiliates	3,540	15,625
Inventories	520,340	367,806
Prepaid expenses and other current assets	110,918	95,859
Total current assets	1,250,299	1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	1,755,416	1,649,572
GOODWILL	1,467,955	1,315,362
INTANGIBLE ASSETS, net of accumulated amortization	1,190,147	1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	190,662	219,550
LOAN RECEIVABLE-AFFILIATE	1,700	22,262
OTHER NONCURRENT ASSETS	217,739	176,039
Total assets	6,073,918	5,560,155
CURRENT LIABILITIES:
Accounts payable-trade	512,104	420,306
Accounts payable-affiliates	6,244	7,193
Accrued expenses and other payables	184,634	214,426
Advance payments received from customers	87,825	56,185
Current maturities of long-term debt	8,046	7,907
Total current liabilities	798,853	706,017
LONG-TERM DEBT, net of debt issuance costs and current maturities	3,063,008	2,912,837
OTHER NONCURRENT LIABILITIES	198,001	247,236
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	58,742	0
EQUITY :
Partners' equity	1,926,861	1,656,515
Accumulated other comprehensive loss	(642)	(157)
Noncontrolling interests	29,095	37,707
Total equity	1,955,314	1,694,065
Total liabilities, convertible preferred units and equity	6,073,918	5,560,155
Liabilities and Equity		5,560,155
Reportable Entity | NGL Energy Partners LP (Parent)
CURRENT ASSETS:
Cash and cash equivalents	10,116	25,749	23,042	29,115
Total current assets	10,116	25,749
INTANGIBLE ASSETS, net of accumulated amortization	0	0
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,290,616	1,404,479
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,689,633	1,254,383
Total assets	2,990,365	2,684,611
CURRENT LIABILITIES:
Accounts payable-affiliates	1	1
Accrued expenses and other payables	16,232	16,887
Total current liabilities	16,233	16,888
LONG-TERM DEBT, net of debt issuance costs and current maturities	989,171	1,011,365
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	58,742
EQUITY :
Partners' equity	1,926,219	1,656,358
Total equity	1,926,219	1,656,358
Total liabilities, convertible preferred units and equity	2,990,365
Liabilities and Equity		2,684,611
Reportable Entity | Guarantor Subsidiaries
CURRENT ASSETS:
Cash and cash equivalents	12,179	784	4,547	9,757
Accounts receivable - trade, net of allowance for doubtful accounts	585,720	516,362
Accounts receivable-affiliates	3,540	15,625
Inventories	519,795	367,250
Prepaid expenses and other current assets	109,969	94,426
Total current assets	1,231,203	994,447
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	1,653,011	1,568,488
GOODWILL	1,448,661	1,313,364
INTANGIBLE ASSETS, net of accumulated amortization	1,166,439	1,146,355
INVESTMENTS IN UNCONSOLIDATED ENTITIES	190,662	219,550
NET INTERCOMPANY RECEIVABLES (PAYABLES)	(1,279,908)	(1,402,360)
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	96,577	42,227
LOAN RECEIVABLE-AFFILIATE	1,700	22,262
OTHER NONCURRENT ASSETS	217,618	175,512
Total assets	4,725,963	4,079,845
CURRENT LIABILITIES:
Accounts payable-trade	510,535	417,707
Accounts payable-affiliates	6,054	7,190
Accrued expenses and other payables	164,918	196,596
Advance payments received from customers	87,094	55,737
Current maturities of long-term debt	7,252	7,109
Total current liabilities	775,853	684,339
LONG-TERM DEBT, net of debt issuance costs and current maturities	2,067,264	1,894,428
OTHER NONCURRENT LIABILITIES	193,213	246,695
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	0
EQUITY :
Partners' equity	1,690,096	1,254,384
Accumulated other comprehensive loss	(463)	(1)
Noncontrolling interests	0
Total equity	1,689,633	1,254,383
Total liabilities, convertible preferred units and equity	4,725,963
Liabilities and Equity		4,079,845
Reportable Entity | Non-Guarantor Subsidiaries
CURRENT ASSETS:
Cash and cash equivalents	1,132	1,643	$ 2,464	$ 2,431
Accounts receivable - trade, net of allowance for doubtful accounts	6,354	4,652
Accounts receivable-affiliates	0	0
Inventories	545	556
Prepaid expenses and other current assets	949	1,433
Total current assets	8,980	8,284
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	102,405	81,084
GOODWILL	19,294	1,998
INTANGIBLE ASSETS, net of accumulated amortization	23,708	2,535
INVESTMENTS IN UNCONSOLIDATED ENTITIES	0	0
NET INTERCOMPANY RECEIVABLES (PAYABLES)	(10,708)	(2,119)
OTHER NONCURRENT ASSETS	121	527
Total assets	143,800	92,309
CURRENT LIABILITIES:
Accounts payable-trade	1,569	2,599
Accounts payable-affiliates	189	2
Accrued expenses and other payables	3,484	943
Advance payments received from customers	731	448
Current maturities of long-term debt	794	798
Total current liabilities	6,767	4,790
LONG-TERM DEBT, net of debt issuance costs and current maturities	6,573	7,044
OTHER NONCURRENT LIABILITIES	4,788	541
EQUITY :
Partners' equity	125,851	80,090
Accumulated other comprehensive loss	(179)	(156)
Total equity	125,672	79,934
Total liabilities, convertible preferred units and equity	143,800
Liabilities and Equity		92,309
Consolidating Adjustments
CURRENT ASSETS:
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	(1,786,210)	(1,296,610)
Total assets	(1,786,210)	(1,296,610)
EQUITY :
Partners' equity	(1,815,305)	(1,334,317)
Noncontrolling interests	29,095	37,707
Total equity	(1,786,210)	(1,296,610)
Total liabilities, convertible preferred units and equity	$ (1,786,210)
Liabilities and Equity		$ (1,296,610)

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Condensed Consolidating Statement of Operations
REVENUES	$ 3,045,538	$ 3,193,195	$ 5,767,508	$ 6,731,664
COST OF SALES	2,928,730	3,005,826	5,495,170	6,328,377
OPERATING COSTS AND EXPENSES:
Operating	73,255	97,630	148,427	203,220
General and administrative	27,926	29,298	69,797	91,779
Depreciation and amortization	50,603	56,761	99,509	116,592
Loss (gain) on disposal or impairment of assets, net	852	1,291	(203,467)	1,712
Revaluation of liabilities	0	(15,909)	0	(27,104)
Operating (Loss) Income	(35,828)	18,298	158,072	17,088
OTHER INCOME (EXPENSE):
Equity in earnings (loss) of unconsolidated entities	53	2,432	447	11,150
Revaluation of investments	0	0	(14,365)	0
Interest expense	(33,442)	(31,571)	(63,880)	(62,373)
Gain on early extinguishment of liabilities	938	0	30,890	0
Other income, net	2,081	1,955	5,853	780
Income (loss) before income taxes	(66,198)	(8,886)	117,017	(33,355)
INCOME TAX BENEFIT (EXPENSE)	(460)	2,786	(922)	2,248
Net Loss (Income)	(66,658)	(6,100)	116,095	(31,107)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	59	(3,497)	(5,774)	(7,847)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(8,668)	0	(12,052)	0
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	45	(16,185)	(158)	(31,559)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	(75,222)	(25,782)	98,111	(70,513)
Reportable Entity | NGL Energy Partners LP (Parent)
OTHER INCOME (EXPENSE):
Interest expense	(16,364)	(17,913)	(32,690)	(35,714)
Gain on early extinguishment of liabilities			8,614
Income (loss) before income taxes	(16,364)	(17,913)	(24,076)	(35,714)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(50,235)	8,316	134,397	(3,240)
Net Loss (Income)	(66,599)	(9,597)	110,321	(38,954)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	(66,599)	(9,597)	110,321	(38,954)
Reportable Entity | Guarantor Subsidiaries
Condensed Consolidating Statement of Operations
REVENUES	3,034,053	3,153,370	5,749,034	6,650,251
COST OF SALES	2,928,036	3,009,777	5,493,864	6,333,438
OPERATING COSTS AND EXPENSES:
Operating	68,750	75,023	139,631	160,323
General and administrative	27,686	24,538	69,312	81,208
Depreciation and amortization	47,740	45,006	94,049	90,545
Loss (gain) on disposal or impairment of assets, net	896	1,294	(203,443)	1,715
Revaluation of liabilities		(15,909)		(27,104)
Operating (Loss) Income	(39,055)	13,641	155,621	10,126
OTHER INCOME (EXPENSE):
Equity in earnings (loss) of unconsolidated entities	53	(23)	447	2,872
Revaluation of investments			(14,365)
Interest expense	(16,870)	(11,351)	(30,898)	(22,344)
Gain on early extinguishment of liabilities	938		22,276
Other income, net	2,154	1,916	5,990	691
Income (loss) before income taxes	(52,780)	4,183	139,071	(8,655)
INCOME TAX BENEFIT (EXPENSE)	(460)	2,793	(922)	2,286
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	3,005	1,340	(3,752)	3,129
Net Loss (Income)	(50,235)	8,316	134,397	(3,240)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	(50,235)	8,316	134,397	(3,240)
Reportable Entity | Non-Guarantor Subsidiaries
Condensed Consolidating Statement of Operations
REVENUES	12,118	49,442	19,469	100,621
COST OF SALES	1,327	5,610	2,301	14,022
OPERATING COSTS AND EXPENSES:
Operating	4,505	22,663	8,796	43,022
General and administrative	240	4,760	485	10,571
Depreciation and amortization	2,863	11,755	5,460	26,047
Loss (gain) on disposal or impairment of assets, net	(44)	(3)	(24)	(3)
Operating (Loss) Income	3,227	4,657	2,451	6,962
OTHER INCOME (EXPENSE):
Equity in earnings (loss) of unconsolidated entities	0	2,455	0	8,278
Interest expense	(291)	(2,381)	(453)	(4,463)
Other income, net	10	113	24	237
Income (loss) before income taxes	2,946	4,844	2,022	11,014
INCOME TAX BENEFIT (EXPENSE)	0	(7)	0	(38)
Net Loss (Income)	2,946	4,837	2,022	10,976
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	2,946	4,837	2,022	10,976
Consolidating Adjustments
Condensed Consolidating Statement of Operations
REVENUES	(633)	(9,617)	(995)	(19,208)
COST OF SALES	(633)	(9,561)	(995)	(19,083)
OPERATING COSTS AND EXPENSES:
Operating	0	(56)	0	(125)
OTHER INCOME (EXPENSE):
Interest expense	83	74	161	148
Other income, net	(83)	(74)	(161)	(148)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	47,230	(9,656)	(130,645)	111
Net Loss (Income)	47,230	(9,656)	(130,645)	111
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	59	(3,497)	(5,774)	(7,847)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(8,668)		(12,052)
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	45	(16,185)	(158)	(31,559)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$ 38,666	$ (29,338)	$ (148,629)	$ (39,295)

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information - Condensed Consolidating Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Condensed Consolidating Statement of Comprehensive Income (Loss)
Net (loss) income	$ (66,658)	$ (6,100)	$ 116,095	$ (31,107)
Other comprehensive loss	(333)	(19)	(485)	(27)
Comprehensive income (loss)	(66,991)	(6,119)	115,610	(31,134)
Reportable Entity | NGL Energy Partners LP (Parent)
Condensed Consolidating Statement of Comprehensive Income (Loss)
Net (loss) income	(66,599)	(9,597)	110,321	(38,954)
Comprehensive income (loss)	(66,599)	(9,597)	110,321	(38,954)
Reportable Entity | Guarantor Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (Loss)
Net (loss) income	(50,235)	8,316	134,397	(3,240)
Other comprehensive loss	(333)	0	(475)	0
Comprehensive income (loss)	(50,568)	8,316	133,922	(3,240)
Reportable Entity | Non-Guarantor Subsidiaries
Condensed Consolidating Statement of Comprehensive Income (Loss)
Net (loss) income	2,946	4,837	2,022	10,976
Other comprehensive loss	0	(19)	(10)	(27)
Comprehensive income (loss)	2,946	4,818	2,012	10,949
Consolidating Adjustments
Condensed Consolidating Statement of Comprehensive Income (Loss)
Net (loss) income	47,230	(9,656)	(130,645)	111
Comprehensive income (loss)	$ 47,230	$ (9,656)	$ (130,645)	$ 111

XML

Condensed Consolidating Guarantor and Non-Guarantor Financial Information - Condensed Consolidating Statements Of Cash Flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	$ (56,399)	$ 174,095
INVESTING ACTIVITIES:
Capital expenditures	(159,680)	(222,276)
Purchases of pipeline capacity allocations	(41,953)	0
Acquisitions of businesses, including acquired working capital, net of cash acquired	(113,297)	(150,546)
Cash flows from commodity derivatives	(25,015)	43,032
Proceeds from sales of assets	396	3,567
Proceeds from sale of TLP common units	112,370	0
Investments in unconsolidated entities	0	(6,926)
Distributions of capital from unconsolidated entities	5,233	8,207
Loan for natural gas liquids facility	0	(3,913)
Payments on loan for natural gas liquids facility	4,324	3,546
Loan to affiliate	(1,700)	(15,621)
Payments on loan to affiliate	655	0
Payment to terminate contract	(16,875)	0
Net cash used in investing activities	(235,542)	(340,930)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	770,000	1,354,700
Payments on revolving credit facilities	(595,500)	(1,006,600)
Repurchases of senior notes	(15,129)	0
Payments on other long-term debt	(4,423)	(2,344)
Debt issuance costs	(320)	(1,380)
Contributions from partners	(442)	45
Contributions from noncontrolling interest owners	966	6,613
Distributions to partners	(83,707)	(154,824)
Distributions to noncontrolling interest owners	(2,750)	(17,780)
Taxes paid on behalf of equity incentive plan participants	0	(19,083)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018	0
Proceeds from sale of common units, net of offering costs	9,383	0
Payments for the early extinguishment of liabilities	(25,884)	0
Common unit repurchases	0	(3,650)
Other	(20)	(112)
Net cash provided by financing activities	287,192	155,585
Net decrease in cash and cash equivalents	(4,749)	(11,250)
Cash and cash equivalents, beginning of period	28,176	41,303
Cash and cash equivalents, end of period	23,427	30,053
Reportable Entity | NGL Energy Partners LP (Parent)
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	(31,541)	(34,469)
FINANCING ACTIVITIES:
Repurchases of senior notes	(15,129)
Debt issuance costs	(255)	49
Contributions from partners	(442)	45
Distributions to partners	(83,707)	(154,824)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	235,018
Proceeds from sale of common units, net of offering costs	9,383
Net changes in advances with consolidated entities	(128,960)	186,776
Common unit repurchases		(3,650)
Net cash provided by financing activities	15,908	28,396
Net decrease in cash and cash equivalents	(15,633)	(6,073)
Cash and cash equivalents, beginning of period	25,749	29,115
Cash and cash equivalents, end of period	10,116	23,042
Reportable Entity | Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	(12,751)	173,058
INVESTING ACTIVITIES:
Capital expenditures	(158,333)	(184,680)
Purchases of pipeline capacity allocations	(41,953)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(113,297)	(150,546)
Cash flows from commodity derivatives	(25,015)	43,032
Proceeds from sales of assets	379	3,565
Proceeds from sale of TLP common units	112,370
Investments in unconsolidated entities		(2,700)
Distributions of capital from unconsolidated entities	5,233	5,652
Loan for natural gas liquids facility		(3,913)
Payments on loan for natural gas liquids facility	4,324	3,546
Loan to affiliate	(1,700)	(15,621)
Payments on loan to affiliate	655
Payment to terminate contract	(16,875)
Net cash used in investing activities	(234,212)	(301,665)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	770,000	1,311,500
Payments on revolving credit facilities	(595,500)	(963,000)
Repurchases of senior notes	0
Payments on other long-term debt	(4,080)	(2,274)
Debt issuance costs	(65)	(180)
Contributions from partners	0	0
Contributions from noncontrolling interest owners	0	0
Distributions to partners	0	0
Distributions to noncontrolling interest owners	0	0
Taxes paid on behalf of equity incentive plan participants		(19,083)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	0
Payments for the early extinguishment of liabilities	(25,884)
Net changes in advances with consolidated entities	113,907	(203,533)
Other	(20)	(33)
Net cash provided by financing activities	258,358	123,397
Net decrease in cash and cash equivalents	11,395	(5,210)
Cash and cash equivalents, beginning of period	784	9,757
Cash and cash equivalents, end of period	12,179	4,547
Reportable Entity | Non-Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	(12,107)	35,506
INVESTING ACTIVITIES:
Capital expenditures	(1,347)	(37,596)
Acquisitions of businesses, including acquired working capital, net of cash acquired	0	0
Proceeds from sales of assets	17	2
Investments in unconsolidated entities		(4,226)
Distributions of capital from unconsolidated entities	0	2,555
Payments on loan for natural gas liquids facility		0
Loan to affiliate		0
Net cash used in investing activities	(1,330)	(39,265)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	0	43,200
Payments on revolving credit facilities	0	(43,600)
Payments on other long-term debt	(343)	(70)
Debt issuance costs	0	(1,249)
Contributions from noncontrolling interest owners	966	6,613
Distributions to noncontrolling interest owners	(2,750)	(17,780)
Net changes in advances with consolidated entities	15,053	16,757
Other	0	(79)
Net cash provided by financing activities	12,926	3,792
Net decrease in cash and cash equivalents	(511)	33
Cash and cash equivalents, beginning of period	1,643	2,431
Cash and cash equivalents, end of period	$ 1,132	$ 2,464