UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2021

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)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbols	Name of Each Exchange on Which Registered
Common units representing Limited Partner Interests	NGL	New York Stock Exchange
Fixed-to-floating rate cumulative redeemable perpetual preferred units	NGL-PB	New York Stock Exchange
Fixed-to-floating rate cumulative redeemable perpetual preferred units	NGL-PC	New York Stock Exchange

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).   Yes ☒   No ☐

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

Large accelerated filer	o	Accelerated filer	x
Non-accelerated filer	o	Smaller reporting company	☐
		Emerging growth company	☐

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

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

At February 4, 2022, there were 129,984,138 common units issued and outstanding.

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets at December 31, 2021 and March 31, 2021	3
	Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2021 and 2020	4
	Unaudited Condensed Consolidated Statements of Comprehensive Loss for the three months and nine months ended December 31, 2021 and 2020	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the three months and nine months ended December 31, 2021 and 2020	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2021 and 2020	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	61
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults Upon Senior Securities	62
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	62
Item 6.	Exhibits	63
SIGNATURES		64

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:

•changes in general economic conditions, including market and macroeconomic disruptions resulting from the ongoing COVID-19 pandemic and related governmental responses;

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

•the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, diesel, and biodiesel;

•the level of crude oil and natural gas drilling and production in areas where we have operations and facilities;

•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;

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

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

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

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

•the effect of energy conservation efforts on product demand;

•energy efficiencies and technological trends;

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

•the effect of executive orders and legislative and regulatory actions on hydraulic fracturing, water disposal and transportation, 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 markets;

•loss of key personnel;

•the ability to renew contracts with key customers;

•the ability to maintain or increase the margins we realize for our services;

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

•the nonpayment, nonperformance or bankruptcy 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;

1

•the ability to successfully identify and complete accretive acquisitions and organic growth projects, and integrate acquired assets and businesses;

•the costs and effects of legal and administrative proceedings; and

•political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and sale of crude oil, refined products, natural gas, natural gas liquids, gasoline, diesel or biodiesel.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Quarterly Report. Except as may be required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks discussed under Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2021.

2

PART I - FINANCIAL INFORMATION

Item 1.    Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(in Thousands, except unit amounts)

	December 31, 2021		March 31, 2021
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,456	$	4,829
Accounts receivable-trade, net of allowance for expected credit losses of $2,227 and $2,192, respectively	1,042,641		725,943
Accounts receivable-affiliates	8,824		9,435
Inventories	333,923		158,467
Prepaid expenses and other current assets	131,696		109,164
Total current assets	1,522,540		1,007,838
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $887,840 and $776,279, respectively	2,483,876		2,706,853
GOODWILL	744,439		744,439
INTANGIBLE ASSETS, net of accumulated amortization of $546,221 and $517,518, respectively	1,152,198		1,262,613
INVESTMENTS IN UNCONSOLIDATED ENTITIES	21,263		22,719
OPERATING LEASE RIGHT-OF-USE ASSETS	122,976		152,146
OTHER NONCURRENT ASSETS	47,479		50,733
Total assets	$	6,094,771	$	5,947,341
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	973,471	$	679,868
Accounts payable-affiliates	260		119
Accrued expenses and other payables	165,031		170,400
Advance payments received from customers	16,240		11,163
Current maturities of long-term debt	2,328		2,183
Operating lease obligations	43,822		47,070
Total current liabilities	1,201,152		910,803
LONG-TERM DEBT, net of debt issuance costs of $46,156 and $55,555, respectively, and current maturities	3,411,757		3,319,030
OPERATING LEASE OBLIGATIONS	78,628		103,637
OTHER NONCURRENT LIABILITIES	108,422		114,615
COMMITMENTS AND CONTINGENCIES (NOTE 7)
CLASS D 9.00% PREFERRED UNITS, 600,000 and 600,000 preferred units issued and outstanding, respectively	551,097		551,097
EQUITY:
General partner, representing a 0.1% interest, 130,114 and 129,724 notional units, respectively	(52,422)		(52,189)
Limited partners, representing a 99.9% interest, 129,984,138 and 129,593,939 common units issued and outstanding, respectively	430,358		582,784
Class B preferred limited partners, 12,585,642 and 12,585,642 preferred units issued and outstanding, respectively	305,468		305,468
Class C preferred limited partners, 1,800,000 and 1,800,000 preferred units issued and outstanding, respectively	42,891		42,891
Accumulated other comprehensive loss	(314)		(266)
Noncontrolling interests	17,734		69,471
Total equity	743,715		948,159
Total liabilities and equity	$	6,094,771	$	5,947,341

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

3

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(in Thousands, except unit and per unit amounts)

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
REVENUES:
Water Solutions	$	130,653	$	98,925	$	397,089	$	275,668
Crude Oil Logistics	607,203		485,289		1,715,657		1,228,169
Liquids Logistics	1,434,020		877,491		3,301,922		1,969,813
Other	—		314		—		942
Total Revenues	2,171,876		1,462,019		5,414,668		3,474,592
COST OF SALES:
Water Solutions	5,030		3,280		21,791		8,559
Crude Oil Logistics	556,531		448,933		1,591,877		1,053,261
Liquids Logistics	1,388,760		826,211		3,187,039		1,857,633
Other	—		455		—		1,363
Total Cost of Sales	1,950,321		1,278,879		4,800,707		2,920,816
OPERATING COSTS AND EXPENSES:
Operating	72,807		61,427		207,610		182,468
General and administrative	18,925		16,044		46,149		50,677
Depreciation and amortization	68,480		78,200		222,145		249,655
Loss on disposal or impairment of assets, net	12,233		373,776		93,463		391,752
Operating Income (Loss)	49,110		(346,307)		44,594		(320,776)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	119		344		765		1,134
Interest expense	(68,379)		(47,252)		(204,004)		(138,148)
Gain on early extinguishment of liabilities, net	9		11,190		1,131		44,292
Other income, net	24		440		2,003		3,060
Loss From Continuing Operations Before Income Taxes	(19,117)		(381,585)		(155,511)		(410,438)
INCOME TAX BENEFIT	135		1,162		820		2,237
Loss From Continuing Operations	(18,982)		(380,423)		(154,691)		(408,201)
Loss From Discontinued Operations, net of Tax	—		(107)		—		(1,746)
Net Loss	(18,982)		(380,530)		(154,691)		(409,947)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	63		34		(705)		(185)
NET LOSS ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	$	(18,919)	$	(380,496)	$	(155,396)	$	(410,132)
NET LOSS FROM CONTINUING OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)	$	(45,233)	$	(403,755)	$	(232,361)	$	(477,503)
NET LOSS FROM DISCONTINUED OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)	$	—	$	(107)	$	—	$	(1,744)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)	$	(45,233)	$	(403,862)	$	(232,361)	$	(479,247)
BASIC LOSS PER COMMON UNIT
Loss From Continuing Operations	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.71)
Loss From Discontinued Operations, net of Tax	$	—	$	—	$	—	$	(0.01)
Net Loss	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.72)
DILUTED LOSS PER COMMON UNIT
Loss From Continuing Operations	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.71)
Loss From Discontinued Operations, net of Tax	$	—	$	—	$	—	$	(0.01)
Net Loss	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.72)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	129,810,245		128,991,414		129,666,303		128,845,214
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	129,810,245		128,991,414		129,666,303		128,845,214

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

4

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Loss

(in Thousands)

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
Net loss	$	(18,982)	$	(380,530)	$	(154,691)	$	(409,947)
Other comprehensive (loss) income	(4)		41		(48)		119
Comprehensive loss	$	(18,986)	$	(380,489)	$	(154,739)	$	(409,828)

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

5

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Three Months and Nine Months Ended December 31, 2021

(in Thousands, except unit amounts)

			Limited Partners
			Preferred			Common			Accumulated Other
	General Partner		Units	Amount		Units	Amount		Comprehensive Income (Loss)		Noncontrolling Interests		Total Equity
BALANCES AT MARCH 31, 2021	$	(52,189)	14,385,642	$	348,359	129,593,939	$	582,784	$	(266)	$	69,471	$	948,159
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(444)		(444)
Sawtooth joint venture disposition (Note 15)	—		—	—		—	—		—		(51,097)		(51,097)
Equity issued pursuant to incentive compensation plan (Note 8)	—		—	—		—	960		—		—		960
Net (loss) income	(159)		—	—		—	(134,781)		—		438		(134,502)
Other comprehensive income	—		—	—		—	—		8		—		8
BALANCES AT JUNE 30, 2021	(52,348)		14,385,642	348,359		129,593,939	448,963		(258)		18,368		763,084
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(513)		(513)
Equity issued pursuant to incentive compensation plan (Note 8)	—		—	—		—	1,048		—		—		1,048
Net (loss) income	(27)		—	—		—	(1,510)		—		330		(1,207)
Other comprehensive loss	—		—	—		—	—		(52)		—		(52)
BALANCES AT SEPTEMBER 30, 2021	(52,375)		14,385,642	348,359		129,593,939	448,501		(310)		18,185		762,360
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(388)		(388)
Common unit repurchases and cancellations (Note 8)	—		—	—		(8,901)	(20)		—		—		(20)
Equity issued pursuant to incentive compensation plan (Note 8)	—		—	—		399,100	749		—		—		749
Net loss	(47)		—	—		—	(18,872)		—		(63)		(18,982)
Other comprehensive loss	—		—	—		—	—		(4)		—		(4)
BALANCES AT DECEMBER 31, 2021	$	(52,422)	14,385,642	$	348,359	129,984,138	$	430,358	$	(314)	$	17,734	$	743,715

6

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Three Months and Nine Months Ended December 31, 2020

(in Thousands, except unit amounts)

			Limited Partners
			Preferred			Common			Accumulated Other
	General Partner		Units	Amount		Units	Amount		Comprehensive Income (Loss)		Noncontrolling Interests		Total Equity
BALANCES AT MARCH 31, 2020	$	(51,390)	14,385,642	$	348,359	128,771,715	$	1,366,152	$	(385)	$	72,954	$	1,735,690
Distributions to general and common unit partners and preferred unitholders	(26)		—	—		—	(47,652)		—		—		(47,678)
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(2,257)		(2,257)
Equity issued pursuant to incentive compensation plan	—		—	—		—	1,349		—		—		1,349
Net (loss) income	(57)		—	—		—	(35,246)		—		51		(35,252)
Other comprehensive income	—		—	—		—	—		44		—		44
Cumulative effect adjustment for adoption of ASU 2016-13	(1)		—	—		—	(1,112)		—		—		(1,113)
BALANCES AT JUNE 30, 2020	(51,474)		14,385,642	348,359		128,771,715	1,283,491		(341)		70,748		1,650,783
Distributions to general and common unit partners and preferred unitholders	(26)		—	—		—	(47,808)		—		—		(47,834)
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(598)		(598)
Equity issued pursuant to incentive compensation plan	—		—	—		—	1,308		—		—		1,308
Net (loss) income	(18)		—	—		—	5,685		—		168		5,835
Other comprehensive income	—		—	—		—	—		34		—		34
BALANCES AT SEPTEMBER 30, 2020	(51,518)		14,385,642	348,359		128,771,715	1,242,676		(307)		70,318		1,609,528
Distributions to general and common unit partners and preferred unitholders	(13)		—	—		—	(36,647)		—		—		(36,660)
Distributions to noncontrolling interest owners	—		—	—		—	—		—		(842)		(842)
Common unit repurchases and cancellations	—		—	—		(50,155)	(134)		—		—		(134)
Equity issued pursuant to incentive compensation plan	—		—	—		446,475	1,170		—		—		1,170
Net loss	(404)		—	—		—	(380,092)		—		(34)		(380,530)
Other comprehensive income	—		—	—		—	—		41		—		41
BALANCES AT DECEMBER 31, 2020	$	(51,935)	14,385,642	$	348,359	129,168,035	$	826,973	$	(266)	$	69,442	$	1,192,573

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

7

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(in Thousands)

	Nine Months Ended December 31,
	2021		2020
OPERATING ACTIVITIES:
Net loss	$	(154,691)	$	(409,947)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations, net of tax	—		1,746
Depreciation and amortization, including amortization of debt issuance costs	235,357		260,054
Gain on early extinguishment of liabilities, net	(1,131)		(44,292)
Non-cash equity-based compensation expense	(1,044)		5,678
Loss on disposal or impairment of assets, net	93,463		391,752
Change in provision for expected credit losses	88		5,693
Net adjustments to fair value of commodity derivatives	42,875		55,162
Equity in earnings of unconsolidated entities	(765)		(1,134)
Distributions of earnings from unconsolidated entities	2,178		3,355
Lower of cost or net realizable value adjustments	6,534		754
Other	1,593		1,405
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(316,477)		(42,759)
Inventories	(194,053)		(100,806)
Other current and noncurrent assets	33,792		34,454
Accounts payable-trade and affiliates	294,230		97,842
Other current and noncurrent liabilities	(15,038)		(71,643)
Net cash provided by operating activities-continuing operations	26,911		187,314
Net cash used in operating activities-discontinued operations	—		(1,714)
Net cash provided by operating activities	26,911		185,600
INVESTING ACTIVITIES:
Capital expenditures	(107,480)		(151,644)
Net settlements of commodity derivatives	(60,972)		(40,815)
Proceeds from sales of assets	8,419		42,121
Proceeds from divestitures of businesses and investments, net	63,489		—
Investments in unconsolidated entities	(350)		(638)
Distributions of capital from unconsolidated entities	393		10
Net cash used in investing activities	(96,501)		(150,966)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	1,342,000		1,016,000
Payments on revolving credit facilities	(1,190,000)		(805,000)
Issuance of term credit agreement	—		250,000
Repayment of term credit agreement	—		(250,000)
Repayment and repurchase of senior unsecured notes	(60,149)		(75,081)
Proceeds from borrowings on other long-term debt	—		48,750
Payments on other long-term debt	(6,772)		(5,013)
Debt issuance costs	(12,503)		(10,145)
Distributions to general and common unit partners and preferred unitholders	—		(118,358)
Distributions to noncontrolling interest owners	(1,345)		(3,697)
Common unit repurchases and cancellations	(20)		(134)
Payments to settle contingent consideration liabilities	(994)		(95,437)
Net cash provided by (used in) financing activities	70,217		(48,115)
Net increase (decrease) in cash and cash equivalents	627		(13,481)
Cash and cash equivalents, beginning of period	4,829		22,704
Cash and cash equivalents, end of period	$	5,456	$	9,223
Supplemental cash flow information:
Cash interest paid	$	162,053	$	145,375
Income taxes paid (net of income tax refunds)	$	1,896	$	2,232
Supplemental non-cash investing and financing activities:
Distributions declared but not paid to preferred unitholders	$	—	$	21,976
Accrued capital expenditures	$	9,949	$	3,146

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

8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1—Organization and Operations

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2021, our operations included three segments:

•Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from oil and natural gas production. We also sell produced water for reuse and brackish non-potable water to our producer customers to be used in their crude oil exploration and production activities. As part of processing water, we aggregate and sell recovered crude oil, also known as skim oil. We also dispose of solids such as tank bottoms, drilling fluids and drilling muds and perform other ancillary services such as truck and frac tank washouts. Our activities in this segment are underpinned by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments, with leading oil and gas companies including large, investment grade producer customers.

•Our Crude Oil Logistics segment purchases crude oil from producers and marketers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs, and provides storage, terminaling, and transportation services through its owned assets. Our activities in this segment are supported by certain long-term, fixed rate contracts which include minimum volume commitments on our pipelines.

•Our Liquids Logistics segment conducts supply operations for natural gas liquids, refined petroleum products and biodiesel to a broad range of commercial, retail and industrial customers across the United States and Canada. These operations are conducted through our 24 company-owned terminals, third-party storage and terminal facilities, common carrier pipelines and a fleet of leased railcars. We also provide marine exports of butane through our facility located in Chesapeake, Virginia.

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 do not control, but can exercise significant influence over, are accounted for using the equity method of accounting. We also own an undivided interest in a crude oil pipeline, and include our proportionate share of assets, liabilities, and expenses related to this pipeline in our unaudited condensed consolidated financial statements.

Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position, results of operations and cash flows 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, 2021 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2021 included in our Annual Report on Form 10-K (“Annual Report”) filed with the SEC on June 3, 2021.

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, 2022.

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.

9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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

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 a deferred tax liability of $43.7 million and $45.8 million at December 31, 2021 and March 31, 2021, respectively, as a result of acquiring corporations in connection with certain of our acquisitions, which is included within other noncurrent liabilities in our unaudited condensed consolidated balance sheets. The deferred tax liability is the tax effected cumulative temporary difference between the GAAP basis and tax basis of the acquired assets within the corporation. For GAAP purposes, certain of the acquired assets will be depreciated and amortized over time which will lower the GAAP basis. The deferred tax benefit recorded during the nine months ended December 31, 2021 was $2.0 million with an effective tax rate of 22.9%. The deferred tax benefit recorded during the nine months ended December 31, 2020 was $3.0 million with an effective tax rate of 23.9%.

We evaluate uncertain tax positions for recognition and measurement in the unaudited condensed 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 unaudited condensed consolidated financial statements. We had no material uncertain tax positions that required recognition in our unaudited condensed consolidated financial statements at December 31, 2021 or March 31, 2021.

Inventories

Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. In performing this analysis, we consider fixed-price forward commitments.

Inventories consist of the following at the dates indicated:

	December 31, 2021		March 31, 2021
	(in thousands)
Propane	$	144,836	$	45,521
Crude oil	92,842		64,916
Butane	56,287		19,189
Biodiesel	22,655		16,169
Ethanol	5,009		3,056
Diesel	3,100		2,252
Other	9,194		7,364
Total	$	333,923	$	158,467

10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Investments in Unconsolidated Entities

Investments we do not control, but can exercise significant influence over, are accounted for using the equity method of accounting. Investments in partnerships and limited liability companies, unless our investment is considered to be minor, and investments in unincorporated joint ventures are also accounted for using the equity method of accounting.

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

Entity	Segment	Ownership Interest	December 31, 2021		March 31, 2021
			(in thousands)
Water services and land company	Water Solutions	50%	$	15,184	$	15,832
Water services and land company	Water Solutions	50%	2,097		2,284
Water services and land company	Water Solutions	10%	2,837		3,254
Aircraft company (1)	Corporate and Other	50%	586		748
Water services company	Water Solutions	50%	414		424
Natural gas liquids terminal company	Liquids Logistics	50%	145		177
Total			$	21,263	$	22,719

(1)    This is an investment with a related party.

Other Noncurrent Assets

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

	December 31, 2021		March 31, 2021
	(in thousands)
Loan receivable (1)	$	3,100	$	2,962
Linefill (2)	28,065		28,110
Minimum shipping fees - pipeline commitments (3)	9,967		13,171
Other	6,347		6,490
Total	$	47,479	$	50,733

(1)    Represents the noncurrent portion of a loan receivable, net of an allowance for an expected credit loss, with a former related party.

(2)    Represents minimum volumes of product we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At December 31, 2021 and March 31, 2021, linefill consisted of 423,978 barrels of crude oil. Linefill held in pipelines we own is included within property, plant and equipment (see Note 4).

(3)    Represents the noncurrent portion of minimum shipping fees paid in excess of volumes shipped, or deficiency credits, for a contract with a crude oil pipeline operator. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 7). As of December 31, 2021, the deficiency credit was $14.2 million, of which $4.2 million is recorded within prepaid expenses and other current assets in our unaudited condensed consolidated balance sheet.

Accrued Expenses and Other Payables

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

	December 31, 2021		March 31, 2021
	(in thousands)
Accrued interest	$	85,383	$	56,299
Derivative liabilities	20,278		21,562
Accrued compensation and benefits	16,300		41,456
Excise and other tax liabilities	7,928		10,970
Product exchange liabilities	12,185		1,188
Other	22,957		38,925
Total	$	165,031	$	170,400

11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 assets, liabilities, equity, net income or cash flows.

Recent Accounting Pronouncements

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in Accounting Standards Codification (“ASC”) 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. This guidance is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. Under our Class D Preferred Unit (as defined in Note 8) agreement, we are permitted to issue common units to redeem a portion of the outstanding Class D Preferred Units. Using the if-converted method, we expect, when the guidance is adopted, our calculation of earnings per unit to be impacted by both an increase in the number of diluted weighted average common units outstanding and a decrease in the amount of Class D Preferred Unit distributions, when they are determined to be dilutive. We do not expect any other provision within this guidance to have an impact on our financial position, results of operations or cash flows related to any debt or preferred units issued prior to adoption, which will be on April 1, 2022.

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” The ASU provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance is effective prospectively upon issuance through December 31, 2022 and may be applied from the beginning of an interim period that includes the issuance date of this ASU. We are currently evaluating the effect that this guidance will have on our financial position, results of operations and cash flows.

Note 3—Loss Per Common Unit

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

	Three Months Ended December 31,		Nine Months Ended December 31,
	2021	2020	2021	2020
Weighted average common units outstanding during the period:
Common units - Basic	129,810,245	128,991,414	129,666,303	128,845,214
Common units - Diluted	129,810,245	128,991,414	129,666,303	128,845,214

For the three months and nine months ended December 31, 2021 and 2020, all potential common units or convertible securities were considered antidilutive.

12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands, except unit and per unit amounts)
Loss from continuing operations	$	(18,982)	$	(380,423)	$	(154,691)	$	(408,201)
Less: Continuing operations loss (income) attributable to noncontrolling interests	63		34		(705)		(185)
Net loss from continuing operations attributable to NGL Energy Partners LP	(18,919)		(380,389)		(155,396)		(408,386)
Less: Distributions to preferred unitholders (1)	(26,361)		(23,770)		(77,198)		(69,594)
Less: Continuing operations net loss allocated to general partner (2)	47		404		233		477
Net loss from continuing operations allocated to common unitholders	$	(45,233)	$	(403,755)	$	(232,361)	$	(477,503)
Loss from discontinued operations, net of tax	$	—	$	(107)	$	—	$	(1,746)
Less: Discontinued operations loss allocated to general partner (2)	—		—		—		2
Net loss from discontinued operations allocated to common unitholders	$	—	$	(107)	$	—	$	(1,744)
Net loss allocated to common unitholders	$	(45,233)	$	(403,862)	$	(232,361)	$	(479,247)
Basic loss per common unit
Loss from continuing operations	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.71)
Loss from discontinued operations, net of tax	$	—	$	—	$	—	$	(0.01)
Net loss	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.72)
Diluted loss per common unit
Loss from continuing operations	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.71)
Loss from discontinued operations, net of tax	$	—	$	—	$	—	$	(0.01)
Net loss	$	(0.35)	$	(3.13)	$	(1.79)	$	(3.72)
Basic weighted average common units outstanding	129,810,245		128,991,414		129,666,303		128,845,214
Diluted weighted average common units outstanding	129,810,245		128,991,414		129,666,303		128,845,214

(1)    Includes cumulative distributions for the three months and nine months ended December 31, 2021, which were earned but not declared or paid (see Note 8 for a further discussion of the suspension of common unit and preferred unit distributions).

(2)    Net loss allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights.

13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 4—Property, Plant and Equipment

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

Description	Estimated Useful Lives			December 31, 2021		March 31, 2021
	(in years)			(in thousands)
Natural gas liquids terminal and storage assets	2	-	30	$	165,986	$	319,554
Pipeline and related facilities	30	-	40	264,606		264,405
Vehicles and railcars	3	-	25	124,784		126,088
Water treatment facilities and equipment	3	-	30	2,047,382		1,930,437
Crude oil tanks and related equipment	2	-	30	236,190		238,924
Barges and towboats	5	-	30	138,006		137,386
Information technology equipment	3	-	7	47,087		50,220
Buildings and leasehold improvements	3	-	40	153,584		165,679
Land				100,214		100,352
Tank bottoms and linefill (1)				30,294		20,237
Other	3	-	20	15,290		15,054
Construction in progress				48,293		114,796
				3,371,716		3,483,132
Accumulated depreciation				(887,840)		(776,279)
Net property, plant and equipment				$	2,483,876	$	2,706,853

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

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Depreciation expense	$	48,404	$	45,139	$	156,855	$	145,152
Capitalized interest expense	$	149	$	450	$	805	$	2,563

We record (gains) losses from the sales of property, plant and equipment and any write-downs in value due to impairment within loss on disposal or impairment of assets, net in our unaudited condensed consolidated statements of operations. The following table summarizes (gains) losses on the disposal or impairment of property, plant and equipment by segment for the periods indicated:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Water Solutions	$	13,238	$	(17,877)	$	22,023	$	(11,137)
Crude Oil Logistics	2,245		(72)		2,189		1,772
Liquids Logistics	(3)		(43)		11,750		4
Corporate and Other	—		1		—		(1)
Total	$	15,480	$	(17,991)	$	35,962	$	(9,362)

14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 5—Intangible Assets

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

				December 31, 2021						March 31, 2021
Description	Amortizable Lives			Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in years)			(in thousands)
Amortizable:
Customer relationships	5	-	25	$	1,241,463	$	(462,846)	$	778,617	$	1,318,638	$	(450,639)	$	867,999
Customer commitments	25			192,000		(19,200)		172,800		192,000		(13,440)		178,560
Pipeline capacity rights	30			7,799		(2,101)		5,698		7,799		(1,907)		5,892
Rights-of-way and easements	1	-	45	91,535		(11,624)		79,911		90,703		(9,270)		81,433
Water rights	13	-	30	100,369		(19,017)		81,352		100,369		(14,454)		85,915
Executory contracts and other agreements	1	-	35	36,249		(21,436)		14,813		48,709		(21,300)		27,409
Non-compete agreements	4	-	5	7,000		(6,063)		937		12,100		(6,102)		5,998
Debt issuance costs (1)	5			21,749		(3,934)		17,815		9,558		(406)		9,152
Total amortizable				1,698,164		(546,221)		1,151,943		1,779,876		(517,518)		1,262,358
Non-amortizable:
Trade names				255		—		255		255		—		255
Total				$	1,698,419	$	(546,221)	$	1,152,198	$	1,780,131	$	(517,518)	$	1,262,613

(1)    Includes debt issuance costs related to the ABL Facility (as defined herein) and the Sawtooth (as defined herein) credit agreement. Debt issuance costs related to the fixed-rate notes are reported as a reduction of the carrying amount of long-term debt.

On June 18, 2021, the Sawtooth credit agreement was paid off and terminated prior to us selling our ownership interest in Sawtooth (see Note 15). We wrote off $0.1 million of debt issuance costs related to the Sawtooth credit agreement. The loss is reported within gain on early extinguishment of liabilities, net within our unaudited condensed consolidated statement of operations.

The weighted-average remaining amortization period for intangible assets is approximately 20.5 years.

Amortization expense is as follows for the periods indicated:

	Three Months Ended December 31,				Nine Months Ended December 31,
Recorded In	2021		2020		2021		2020
	(in thousands)
Depreciation and amortization	$	20,076	$	33,061	$	65,290	$	104,503
Cost of sales	69		77		213		230
Interest expense	1,283		1,595		3,658		4,687
Operating expenses	62		62		185		185
Total	$	21,490	$	34,795	$	69,346	$	109,605

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

Fiscal Year Ending March 31,
2022 (three months)	$	20,680
2023	81,315
2024	74,975
2025	67,405
2026	64,502
2027	60,185
Thereafter	782,881
Total	$	1,151,943

15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 6—Long-Term Debt

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

	December 31, 2021						March 31, 2021
	Face Amount		Unamortized Debt Issuance Costs (1)		Book Value		Face Amount		Unamortized Debt Issuance Costs (1)		Book Value
	(in thousands)
Senior secured notes:
7.500% Notes due 2026 (“2026 Senior Secured Notes”)	$	2,050,000	$	(37,491)	$	2,012,509	$	2,050,000	$	(44,246)	$	2,005,754
Asset-based revolving credit facility (“ABL Facility”)	156,000		—		156,000		4,000		—		4,000
Senior unsecured notes:
7.500% Notes due 2023 (“2023 Notes”)	499,496		(2,276)		497,220		555,251		(3,564)		551,687
6.125% Notes due 2025 (“2025 Notes”)	380,020		(2,666)		377,354		380,020		(3,297)		376,723
7.500% Notes due 2026 (“2026 Notes”)	332,402		(3,661)		328,741		338,402		(4,378)		334,024
Other long-term debt	42,323		(62)		42,261		49,095		(70)		49,025
	3,460,241		(46,156)		3,414,085		3,376,768		(55,555)		3,321,213
Less: Current maturities	2,328		—		2,328		2,183		—		2,183
Long-term debt	$	3,457,913	$	(46,156)	$	3,411,757	$	3,374,585	$	(55,555)	$	3,319,030

(1)    Debt issuance costs related to the ABL Facility and the Sawtooth credit agreement (included in other long-term debt) are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.

2026 Senior Secured Notes

The 2026 Senior Secured Notes bear interest at 7.5%, which is payable on February 1 and August 1 of each year, which began on August 1, 2021. The 2026 Senior Secured Notes mature on February 1, 2026. The 2026 Senior Secured Notes were issued pursuant to an indenture dated February 4, 2021 (the “Indenture”).

The 2026 Senior Secured Notes are secured by first priority liens on substantially all of our assets other than our accounts receivable, inventory, pledged deposit accounts, cash and cash equivalents, renewable energy tax credits and related assets and second priority liens on our accounts receivable, inventory, pledged deposit accounts, cash and cash equivalents, renewable energy tax credits and related assets.

The Indenture contains covenants that, among other things, limit our ability to: pay distributions or make other restricted payments or repurchase stock; incur or guarantee additional indebtedness or issue disqualified stock or certain preferred stock; make certain investments; create or incur liens; sell assets; enter into restrictions affecting the ability of restricted subsidiaries to make distributions, make loans or advances or transfer assets to the guarantors (including the Partnership); enter into certain transactions with our affiliates; designate restricted subsidiaries as unrestricted subsidiaries; and merge, consolidate or transfer or sell all or substantially all of our assets. The Indenture specifically restricts our ability to pay distributions until our total leverage ratio (as defined in the Indenture) for the most recently ended four full fiscal quarters at the time of the distribution is not greater than 4.75 to 1.00. These covenants are subject to a number of important exceptions and qualifications.

Compliance

At December 31, 2021, we were in compliance with the covenants under the 2026 Senior Secured Notes indenture.

ABL Facility

The $500.0 million ABL Facility is subject to a borrowing base, which includes a sub-limit for letters of credit. The initial borrowing base was $500.0 million and the sub-limit for letters of credit is $200.0 million. The ABL Facility is secured by a lien on substantially all of our assets, including among other things, a first priority lien on our accounts receivable, inventory, pledged deposit accounts, cash and cash equivalents, renewable energy tax credits and related assets and a second priority lien on our all of our other assets. At December 31, 2021, we had letters of credit outstanding of approximately $167.0 million. The ABL Facility is scheduled to mature at the earliest of (a) February 4, 2026 or (b) 91 days prior to the earliest

16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

maturity date in respect to any of our indebtedness in an aggregate principal amount of $50.0 million or greater, if such indebtedness is outstanding at such time, subject to certain exceptions.

All borrowings under the ABL Facility bear interest, at our option, at either (i) an alternate base rate plus a margin of 2.00% per year or (ii) an adjusted LIBOR rate plus a margin of 3.00% per year. At December 31, 2021, the borrowings under the ABL Facility had a weighted average interest rate of 4.24%, calculated as the alternate base rate of 3.25% plus a margin of 2.00% on the alternate base rate borrowings and weighted average LIBOR rate of 0.50% plus a margin of 3.00% for the LIBOR borrowings. On December 31, 2021, the interest rate in effect on letters of credit was 3.00%.

The ABL Facility contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, distributions and other restricted payments, investments (including acquisitions) and transactions with affiliates. The ABL Facility contains, as the only financial covenant, a minimum fixed charge coverage ratio financial covenant that is tested based on the financial statements for the most recently ended fiscal quarter upon the occurrence and during the continuation of a Cash Dominion Event (as defined in the ABL Facility). At December 31, 2021, no Cash Dominion Event had occurred.

Compliance

At December 31, 2021, we were in compliance with the covenants under the ABL Facility.

Senior Unsecured Notes

The senior unsecured notes include the 2023 Notes, 2025 Notes and 2026 Notes (collectively, the “Senior Unsecured Notes”).

Repurchases

The following table summarizes repurchases of Senior Unsecured Notes for the periods indicated:

	Three Months Ended December 31,		Nine Months Ended December 31,
	2021		2021
	(in thousands)
2023 Notes
Notes repurchased	$	20,000	$	55,755
Cash paid (excluding payments of accrued interest)	$	19,900	$	54,829
Gain on early extinguishment of debt (1)	$	9	$	636
2026 Notes
Notes repurchased	$	—	$	6,000
Cash paid (excluding payments of accrued interest)	$	—	$	5,320
Gain on early extinguishment of debt (2)	$	—	$	610

(1)    Gain on early extinguishment of debt for the three months and nine months ended December 31, 2021 is inclusive of the write-off of debt issuance costs of $0.1 million and $0.3 million, respectively. The gain is reported within gain on early extinguishment of liabilities, net within our unaudited condensed consolidated statements of operations.

(2)    Gain on early extinguishment of debt for the nine months ended December 31, 2021 is inclusive of the write-off of debt issuance costs of $0.1 million. The gain is reported within gain on early extinguishment of liabilities, net within our unaudited condensed consolidated statements of operations.

Compliance

At December 31, 2021, we were in compliance with the covenants under all of the Senior Unsecured Notes indentures.

Other Long-term Debt

The Sawtooth Caverns, LLC (“Sawtooth”) credit agreement was paid off and terminated prior to us selling our ownership interest in Sawtooth on June 18, 2021 (see Note 15).

17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

On October 29, 2020, we entered into an equipment loan for $45.0 million which bears interest at a rate of 8.6% and is secured by certain of our barges and towboats. We have an aggregate principal balance of $42.3 million at December 31, 2021. The loan matures on November 1, 2027.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2021:

Fiscal Year Ending March 31,	2026 Senior Secured Notes		ABL Facility		Senior Unsecured Notes		Other Long-Term Debt		Total
	(in thousands)
2022 (three months)	$	—	$	—	$	—	$	410	$	410
2023	—		—		—		2,585		2,585
2024	—		—		499,496		2,816		502,312
2025	—		—		380,020		3,068		383,088
2026	2,050,000		156,000		—		3,343		2,209,343
2027	—		—		332,402		3,642		336,044
Thereafter	—		—		—		26,459		26,459
Total	$	2,050,000	$	156,000	$	1,211,918	$	42,323	$	3,460,241

Amortization of Debt Issuance Costs

Amortization expense for debt issuance costs related to long-term debt was $3.0 million and $1.6 million during the three months ended December 31, 2021 and 2020, respectively, and $9.2 million and $5.3 million during the nine months ended December 31, 2021 and 2020, respectively.

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

Fiscal Year Ending March 31,
2022 (three months)	$	3,030
2023	12,120
2024	11,607
2025	10,812
2026	8,535
2027	46
Thereafter	6
Total	$	46,156

Note 7—Commitments and Contingencies

Legal Contingencies

In August 2015, LCT Capital, LLC (“LCT”) filed a lawsuit against NGL Energy Holdings LLC (the “GP”) and the Partnership seeking payment for investment banking services relating to the purchase of TransMontaigne Inc. and related assets in July 2014. After pre-trial rulings, LCT was limited to pursuing claims of (i) quantum meruit (the value of the services rendered by LCT) and (ii) fraudulent misrepresentation against the defendants. Following a jury trial conducted in Delaware state court from July 23, 2018 through August 1, 2018, the jury returned a verdict consisting of an award of $4.0 million for quantum meruit and $29.0 million for fraudulent misrepresentation, subject to statutory interest. On December 5, 2019, in response to the defendants’ post-trial motion, the Court issued an Order overturning the jury’s damages award and ordering the case to be set for a damages-only trial (the “December 5th Order”). Both parties filed applications with the trial court asking the trial court to certify the December 5th Order for interlocutory, immediate review by the Appellate Court. On January 7, 2020, the Supreme Court of Delaware (“Supreme Court”) entered an Order accepting an interlocutory appeal of various issues relating to both the quantum meruit and fraudulent misrepresentation verdicts. The Supreme Court heard oral arguments of the parties on November 4, 2020, took the matters presented under advisement and on January 28, 2021, issued a ruling that (a) LCT is not entitled to “benefit-of-the-bargain” damages on its fraud claim; (b) LCT is not entitled to receive fraudulent misrepresentation damages separate from its quantum meruit damages; (c) the trial court abused its discretion when it ordered a new trial on damages relating to LCT’s claim of fraudulent misrepresentation; and (d) the trial court properly ordered a new trial on LCT’s

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

claim of quantum meruit damages. The date for a new trial, to be limited to the quantum meruit claim, has been set by the trial court for November 7, 2022. Any allocation of the ultimate verdict award, if any, between the GP and the Partnership will be made by the board of directors of our general partner once all information is available to it and after the new trial, any post-trial and/or any appellate process has concluded and the verdict is final as a matter of law. As of December 31, 2021, we have accrued $2.5 million related to this matter.

We are party to various other 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

At December 31, 2021, we have an environmental liability, measured on an undiscounted basis, of $1.4 million, which is recorded within accrued expenses and other payables in our unaudited condensed consolidated balance sheet. Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

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

Balance at March 31, 2021	$	28,079
Liabilities incurred	1,813
Liabilities associated with disposed assets (1)	(1,633)
Accretion expense	1,272
Balance at December 31, 2021	$	29,531

(1)    Relates primarily to the disposition of Sawtooth (see Note 15).

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

Pipeline Capacity Agreements

We have noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement, with some contracts containing provisions that allow us to continue shipping up to six months after the maturity date of the contract in order to recapture previously paid minimum shipping delinquency fees. We currently have an asset recorded in prepaid expenses and other current assets and in other noncurrent assets in our unaudited condensed consolidated balance sheet for minimum shipping fees paid in both the current and previous periods that are expected to be recovered in future periods by exceeding the minimum monthly volumes (see Note 2).

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes future minimum throughput payments under these agreements at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	8,708
2023	35,314
2024	35,410
2025	30,897
Total	$	110,329

Sales and Purchase Contracts

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

At December 31, 2021, we had the following commodity purchase commitments (in thousands):

	Crude Oil (1)			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Commodity Purchase Commitments:
2022 (three months)	$	128,709	1,818	$	12,646	14,472
2023	—		—	6,278		7,812
2024	—		—	4,588		6,048
Total	$	128,709	1,818	$	23,512	28,332
Index-Price Commodity Purchase Commitments:
2022 (three months)	$	1,146,503	15,880	$	437,705	367,994
2023	2,506,678		37,234	30,002		30,206
2024	1,823,070		29,473	15,619		25,200
2025	1,345,043		22,775	—		—
2026	570,834		10,411	—		—
Total	$	7,392,128	115,773	$	483,326	423,400

(1)    Our crude oil index-price purchase commitments exceed our crude oil index-price sales commitments (presented below) due primarily to our long-term purchase commitments for crude oil that we purchase and ship on the Grand Mesa Pipeline. As these purchase commitments are deliver-or-pay contracts, whereby our counterparty is required to pay us for any volumes not delivered, we have not entered into corresponding long-term sales contracts for volumes we may not receive.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At December 31, 2021, we had the following commodity sale commitments (in thousands):

	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Commodity Sale Commitments:
2022 (three months)	$	126,951	1,798	$	112,214	94,382
2023	—		—	28,853		30,897
2024	—		—	7,844		9,693
2025	—		—	46		50
Total	$	126,951	1,798	$	148,957	135,022
Index-Price Commodity Sale Commitments:
2022 (three months)	$	1,049,611	13,910	$	510,948	363,161
2023	1,120,340		15,797	31,109		23,416
2024	669,274		10,248	—		—
2025	632,963		10,220	—		—
2026	23,617		389	—		—
Total	$	3,495,805	50,564	$	542,057	386,577

We account for the contracts shown in the tables above using the normal purchase and normal sale election. Under this accounting policy election, we do not record the physical contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the tables above may have offsetting derivative contracts (described in Note 9) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value in our unaudited condensed consolidated balance sheet and are not included in the tables above. These contracts are included in the derivative disclosures in Note 9 and represent $33.5 million of our prepaid expenses and other current assets and $19.3 million of our accrued expenses and other payables at December 31, 2021.

Other Commitments

We have noncancelable agreements for product storage, railcar spurs and real estate. The following table summarizes future minimum payments under these agreements at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	2,429
2023	7,240
2024	5,786
2025	1,183
2026	1,164
2027	1,156
Thereafter	5,396
Total	$	24,354

As part of the acquisition of Hillstone Environmental Partners, LLC, we assumed an obligation to pay a quarterly subsidy payment in the event that specified volumetric thresholds are not exceeded at a third-party facility. This agreement expires on December 31, 2022. For the three months and nine months ended December 31, 2021, we recorded $0.6 million and $1.7 million, respectively, and for the three months and nine months ended December 31, 2020, we recorded $0.6 million and $2.0 million, respectively, within operating expense in our unaudited condensed consolidated statements of operations. At December 31, 2021, the range of potential payments we could be obligated to make pursuant to the subsidy agreement could be from $0.0 million to $3.2 million.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 8—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. At December 31, 2021, we owned 8.69% of our general partner.

General Partner Contributions

In connection with the issuance of common units for the vesting of restricted units during the nine months ended December 31, 2021, we issued 390 notional units to our general partner for less than $0.1 million in order to maintain its 0.1% interest in us.

Common Unit Repurchase Program

On August 30, 2019, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $150.0 million of our outstanding common units through September 30, 2021, from time to time in the open market or in other privately negotiated transactions. We did not repurchase any units under this plan and this plan has expired.

Suspension of Common Unit and Preferred Unit Distributions

The board of directors of our general partner temporarily suspended all distributions (common unit distributions beginning with the quarter ended December 31, 2020 and preferred unit distributions beginning with the quarter ended March 31, 2021) in order to deleverage our balance sheet and meet the financial performance ratios set within the Indenture of the 2026 Senior Secured Notes, as discussed further in Note 6.

Class B Preferred Units

As of December 31, 2021, there were 12,585,642 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) outstanding.

The current distribution rate for the Class B Preferred Units is 9.00% per year of the $25.00 liquidation preference per unit (equal to $2.25 per unit per year). For the quarter ended December 31, 2021, we did not declare or pay distributions to the holders of the Class B Preferred Units, thus the quarterly distribution for December 31, 2021 is $0.5625 and the cumulative distribution since suspension for each Class B Preferred Unit is $2.25. In addition, the amount of cumulative but unpaid distributions shall continue to accumulate at the then applicable rate until all unpaid distributions have been paid in full. The total amount due as of December 31, 2021 is $29.2 million.

Class C Preferred Units

As of December 31, 2021, there were 1,800,000 of our 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) outstanding.

The current distribution rate for the Class C Preferred Units is 9.625% per year of the $25.00 liquidation preference per unit (equal to $2.41 per unit per year). For the quarter ended December 31, 2021, we did not declare or pay distributions to the holders of the Class C Preferred Units, thus the quarterly distribution for December 31, 2021 is $0.6016 and the cumulative distribution since suspension for each Class C Preferred Unit is $2.4062. In addition, the amount of cumulative but unpaid distributions shall continue to accumulate at the then applicable rate until all unpaid distributions have been paid in full. The total amount due as of December 31, 2021 is $4.5 million.

Class D Preferred Units

As of December 31, 2021, there were 600,000 preferred units (“Class D Preferred Units”) and warrants exercisable to purchase an aggregate of 25,500,000 common units outstanding.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The current distribution rate for the Class D Preferred Units is 9.00% per year per unit (equal to $90.00 per every $1,000 in unit value per year), plus an additional 1.5% rate increase due to us exceeding the adjusted total leverage ratio and due to a Class D distribution payment default, as defined within the amended and restated limited partnership agreement. For the quarter ended December 31, 2021, we did not declare or pay distributions to the holders of the Class D Preferred Units, thus the average quarterly distribution at December 31, 2021 is $27.32 and the average cumulative distribution since suspension for each Class D Preferred unit is $107.96. In addition, the amount of cumulative but unpaid distributions shall continue to accumulate at the then applicable rate until all unpaid distributions have been paid in full. The total amount due as of December 31, 2021 is $67.3 million.

Equity-Based Incentive Compensation

Our general partner adopted a long-term incentive plan (“LTIP”), which allowed for the issuance of equity-based compensation. Our general partner granted certain restricted units to employees and directors, which vest in tranches, subject to the continued service of the recipients through the vesting date (the “Service Awards”). The Service Awards may also vest upon a change of control, at the discretion of the board of directors of our general partner. No distributions accrue to or are paid on the Service Awards during the vesting period. The LTIP expired on May 10, 2021.

The following table summarizes the Service Award activity during the nine months ended December 31, 2021:

Unvested Service Award units at March 31, 2021	446,975
Units granted	3,294,750
Units vested and issued	(399,100)
Units forfeited	(331,075)
Unvested Service Award units at December 31, 2021	3,011,550

In connection with the vesting of certain Service Award units during the nine months ended December 31, 2021, we canceled 8,901 of the newly-vested common units in satisfaction of less than $0.1 million of employee tax liability paid by us. Pursuant to the expiration of the LTIP discussed below, those canceled units are not available for future grants.

The following table summarizes the scheduled vesting of our unvested Service Award units at December 31, 2021:

Fiscal Year Ending March 31,
2022 (three months)	752,700
2023	1,505,775
2024	753,075
Total	3,011,550

Service Awards are valued at the average of the high/low sales price as of the grant date less the present value of the expected distribution stream over the vesting period using a risk-free interest rate. The weighted-average grant price for the nine months ended December 31, 2021 was $2.15 per Service Award. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, over the requisite service period of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion of the grant-date value of the award that is vested at that date.

During the three months ended December 31, 2021 and 2020, we recorded compensation expense related to Service Award units of $0.7 million and $1.2 million, respectively. During the nine months ended December 31, 2021 and 2020, we recorded compensation expense related to Service Award units of $2.8 million and $3.8 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	523
2023	3,222
2024	1,348
Total	$	5,093

As the LTIP expired on May 10, 2021, we have no common units available for grant and any current unvested Service Awards that are forfeited, canceled or expired will not be available for future grants.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 9—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 unaudited condensed consolidated balance sheets at the dates indicated:

	December 31, 2021				March 31, 2021
	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
	(in thousands)
Level 1 measurements	$	39,882	$	(13,497)	$	12,312	$	(17,857)
Level 2 measurements	33,588		(20,417)		37,520		(24,474)
	73,470		(33,914)		49,832		(42,331)
Netting of counterparty contracts (1)	(13,550)		13,550		(12,648)		12,648
Net cash collateral (held) provided	(5,755)		—		2,660		5,543
Commodity derivatives	$	54,165	$	(20,364)	$	39,844	$	(24,140)

(1)    Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty. Our physical contracts that do not qualify as normal purchase normal sale transactions are not subject to such netting arrangements.

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

	December 31, 2021		March 31, 2021
	(in thousands)
Prepaid expenses and other current assets	$	54,165	$	39,844
Accrued expenses and other payables	(20,278)		(21,562)
Other noncurrent liabilities	(86)		(2,578)
Net commodity derivative asset	$	33,801	$	15,704

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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

Contracts	Settlement Period	Net Long (Short) Notional Units (in barrels)	Fair Value of Net Assets (Liabilities)
		(in thousands)
At December 31, 2021:
Crude oil fixed-price (1)	January 2022–December 2023	(1,030)	$	27,054
Propane fixed-price (1)	January 2022–December 2023	6	6,145
Refined products fixed-price (1)	January 2022–December 2022	(278)	(2,084)
Butane fixed-price (1)	January 2022–December 2023	(446)	(5,273)
Other	January 2022–December 2022		13,714
			39,556
Net cash collateral held			(5,755)
Net commodity derivative asset			$	33,801
At March 31, 2021:
Crude oil fixed-price (1)	April 2021–December 2023	(1,850)	$	(5,414)
Propane fixed-price (1)	April 2021–December 2023	(195)	2,188
Refined products fixed-price (1)	April 2021–January 2022	(503)	1,928
Butane fixed-price (1)	April 2021–March 2022	(753)	(3,764)
Other	April 2021–June 2022		12,563
			7,501
Net cash collateral provided			8,203
Net commodity derivative asset			$	15,704

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

During the three months ended December 31, 2021 and 2020, we recorded net losses of $2.2 million and $24.6 million, respectively, from our commodity derivatives to revenues and cost of sales in our unaudited condensed consolidated statements of operations. During the nine months ended December 31, 2021 and 2020, we recorded net losses of $42.9 million and $55.2 million, respectively, from our commodity derivatives to revenues and cost of sales in our unaudited condensed consolidated statements of operations. The amounts for the three months and nine months ended December 31, 2020 do not include net gains and losses related to Mid-Con (as defined herein) and Gas Blending (as defined herein), as these amounts have been classified as discontinued operations within our unaudited condensed consolidated statements of operations (see Note 16).

Credit Risk

We have credit policies that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2021, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our unaudited condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

The ABL Facility is variable-rate debt with interest rates that are generally indexed to the Wall Street Journal prime rate or LIBOR interest rate (or successor rate). At December 31, 2021, we had $156.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 4.24%.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at December 31, 2021 (in thousands):

Senior Secured Notes:
2026 Senior Secured Notes	$	2,109,826
Senior Unsecured Notes:
2023 Notes	$	514,734
2025 Notes	$	327,134
2026 Notes	$	285,312

For the 2026 Senior Secured Notes and Senior Unsecured Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 2 in the fair value hierarchy.

Note 10—Segments

The following table summarizes revenues 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.

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Revenues:
Water Solutions:
Topic 606 revenues
Disposal service fees	$	102,917	$	82,008	$	303,106	$	239,390
Sale of recovered crude oil	17,865		6,778		48,848		16,532
Sale of water	6,842		6,386		31,694		10,267
Other service revenues	3,029		3,753		13,441		9,479
Total Water Solutions revenues	130,653		98,925		397,089		275,668
Crude Oil Logistics:
Topic 606 revenues
Crude oil sales	588,729		455,790		1,660,225		1,104,692
Crude oil transportation and other	18,826		28,407		56,088		118,615
Non-Topic 606 revenues	2,153		2,919		6,518		9,193
Elimination of intersegment sales	(2,505)		(1,827)		(7,174)		(4,331)
Total Crude Oil Logistics revenues	607,203		485,289		1,715,657		1,228,169
Liquids Logistics:
Topic 606 revenues
Refined products sales	503,348		286,640		1,340,725		785,968
Propane sales	396,457		276,459		776,157		534,525
Butane sales	296,481		191,710		582,358		336,827
Other product sales	155,556		99,624		409,452		238,377
Service revenues	361		4,685		8,849		17,710
Non-Topic 606 revenues	81,817		20,302		185,705		59,816
Elimination of intersegment sales	—		(1,929)		(1,324)		(3,410)
Total Liquids Logistics revenues	1,434,020		877,491		3,301,922		1,969,813
Corporate and Other:
Non-Topic 606 revenues	—		314		—		942
Total Corporate and Other revenues	—		314		—		942
Total	$	2,171,876	$	1,462,019	$	5,414,668	$	3,474,592

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following tables summarize depreciation and amortization expense (including amortization expense recorded within interest expense, cost of sales and operating expenses in Note 5 and Note 6) and operating income (loss) by segment for the periods indicated.

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Depreciation and Amortization:
Water Solutions	$	50,877	$	53,388	$	164,651	$	173,865
Crude Oil Logistics	12,166		16,513		37,029		50,540
Liquids Logistics	3,824		7,071		15,627		22,406
Corporate and Other	6,066		4,576		18,050		13,243
Total	$	72,933	$	81,548	$	235,357	$	260,054
Operating Income (Loss):
Water Solutions	$	19,851	$	15,821	$	60,206	$	(13,503)
Crude Oil Logistics	21,291		(382,192)		37,941		(310,633)
Liquids Logistics	23,158		32,438		(18,790)		51,338
Corporate and Other	(15,190)		(12,374)		(34,763)		(47,978)
Total	$	49,110	$	(346,307)	$	44,594	$	(320,776)

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 December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Water Solutions	$	21,254	$	5,177	$	81,807	$	38,139
Crude Oil Logistics	515		785		1,986		9,555
Liquids Logistics	4,248		2,572		10,308		7,292
Corporate and Other	341		2,983		1,504		10,887
Total	$	26,358	$	11,517	$	95,605	$	65,873

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

	December 31, 2021		March 31, 2021
	(in thousands)
Long-lived assets, net:
Water Solutions	$	2,997,529	$	3,104,450
Crude Oil Logistics	1,059,922		1,090,578
Liquids Logistics (1)	394,897		626,221
Corporate and Other	51,141		44,802
Total	$	4,503,489	$	4,866,051

(1)    Includes $18.5 million and $20.9 million of non-US long-lived assets at December 31, 2021 and March 31, 2021, respectively.

	December 31, 2021		March 31, 2021
	(in thousands)
Total assets:
Water Solutions	$	3,142,021	$	3,204,850
Crude Oil Logistics	1,895,169		1,665,005
Liquids Logistics (1)	986,602		1,003,370
Corporate and Other	70,979		74,116
Total	$	6,094,771	$	5,947,341

27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

(1)    Includes $60.6 million and $37.9 million of non-US total assets at December 31, 2021 and March 31, 2021, respectively.

Note 11—Transactions with Affiliates

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Sales to entities affiliated with management	$	—	$	5,369	$	—	$	7,492
Purchases from entities affiliated with management	$	957	$	393	$	1,045	$	684
Purchases from equity method investees	$	243	$	689	$	784	$	1,434
Sales to WPX (1)			$	16,888			$	39,129
Purchases from WPX (1)			$	100,427			$	216,487

(1)    As previously reported, a member of the board of directors of our general partner was an executive officer of WPX Energy, Inc. (“WPX”) and has subsequently retired. Therefore, we are no longer classifying transactions with WPX as a related party. The prior year amounts relate to purchases and sales of crude oil with WPX as well as the treatment and disposal of produced water and solids received from WPX.

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

	December 31, 2021		March 31, 2021
	(in thousands)
NGL Energy Holdings LLC	$	8,385	$	8,245
Equity method investees	438		462
Entities affiliated with management	1		728
Total	$	8,824	$	9,435

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

	December 31, 2021		March 31, 2021
	(in thousands)
Equity method investees	$	37	$	107
Entities affiliated with management	223		12
Total	$	260	$	119

Other Related Party Transactions

Guarantee of Outstanding Loan for KAIR2014 LLC (“KAIR2014”)

In connection with the purchase of our 50% interest in KAIR2014, we executed a joint and several guarantee for the benefit of the lender for KAIR2014’s outstanding loan. The other owner of KAIR2014 is a party to a similar guarantee. This guarantee obligates us for the payment and performance of KAIR2014 with respect to the repayment of the loan. As of December 31, 2021, the outstanding balance of the loan is approximately $2.6 million and the loan matures in September 2023. As the guarantee is joint and several, we could be liable for the entire outstanding balance of the loan. The loan is collateralized by the airplane owned by KAIR2014 and in the event of a default, the lender could seek payment in full from us. As of December 31, 2021, no accrual has been recorded related to this guarantee.

Note 12—Revenue from Contracts with Customers

We recognize revenue for services and products under revenue contracts as our obligations to either perform services or deliver or sell products under the contracts are satisfied. Our revenue contracts in scope under ASC 606 primarily have a single performance obligation and we do not receive material amounts of non-cash consideration. Our costs to obtain or fulfill our revenue contracts were not material as of December 31, 2021.

The majority of our revenue agreements are within scope under ASC 606 and the remainder of our revenue comes from contracts that are accounted for as derivatives under ASC 815 or that contain nonmonetary exchanges or leases and are in scope under Topics 845 and 842, respectively. See Note 10 for a detail of disaggregated revenue. Revenue from contracts

28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

accounted for as derivatives under ASC 815 within our Liquids Logistics segment includes $15.6 million of net gains related to changes in the mark-to-market value of these arrangements recorded during the nine months ended December 31, 2021.

Remaining Performance Obligations

Most of our service contracts are such that we have the right to consideration from a customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Therefore, we are utilizing the practical expedient in ASC 606-10-55-18 under which we recognize revenue in the amount to which we have the right to invoice. Applying this practical expedient, we are not required to disclose the transaction price allocated to remaining performance obligations under these agreements. The following table summarizes the amount and timing of revenue recognition for such contracts at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	34,481
2023	104,452
2024	85,386
2025	62,483
2026	17,240
2027	3,727
Thereafter	2,071
Total	$	309,840

Contract Assets and Liabilities

The following tables summarize the balances of our contract assets and liabilities at the dates indicated:

	December 31, 2021		March 31, 2021
	(in thousands)
Accounts receivable from contracts with customers	$	503,351	$	436,682

Contract liabilities balance at March 31, 2021	$	10,896
Payment received and deferred	39,874
Payment recognized in revenue	(26,582)
Disposition of Sawtooth (see Note 15)	(8,234)
Contract liabilities balance at December 31, 2021	$	15,954

Note 13—Leases

Lessee Accounting

Our leasing activity primarily consists of product storage, office space, real estate, railcars, and equipment.

The following table summarizes the components of our lease expense for the periods indicated:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Operating lease expense	$	14,180	$	17,048	$	44,474	$	53,278
Variable lease expense	5,725		4,737		15,978		13,950
Short-term lease expense	60		293		219		1,094
Total	$	19,965	$	22,078	$	60,671	$	68,322

29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes maturities of our operating lease obligations at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	12,997
2023	45,437
2024	29,069
2025	16,698
2026	8,416
2027	4,593
Thereafter	38,820
Total lease payments	156,030
Less imputed interest	(33,580)
Total operating lease obligations	$	122,450

The following table summarizes supplemental cash flow and non-cash information related to our operating leases for the periods indicated:

	Nine Months Ended December 31,
	2021		2020
	(in thousands)
Cash paid for amounts included in the measurement of operating lease obligations	$	43,919	$	52,849
Operating lease right-of-use assets obtained in exchange for operating lease obligations	$	11,738	$	24,073

Lessor Accounting and Subleases

Our lessor arrangements include storage and railcar contracts. We also, from time to time, sublease certain of our storage capacity and railcars to third parties. Fixed rental revenue is recognized on a straight-line basis over the lease term. During the three months ended December 31, 2021 and 2020, fixed rental revenue was $3.7 million, which includes $0.5 million of sublease revenue, and $4.1 million, which includes $0.5 million of sublease revenue, respectively. During the nine months ended December 31, 2021 and 2020, fixed rental revenue was $10.9 million, which includes $1.1 million of sublease revenue, and $12.6 million, which includes $1.9 million of sublease revenue, respectively.

The following table summarizes future minimum lease payments receivable under various noncancelable operating lease agreements at December 31, 2021 (in thousands):

Fiscal Year Ending March 31,
2022 (three months)	$	3,089
2023	9,614
2024	4,806
2025	691
2026	415
2027	415
Thereafter	422
Total	$	19,452

Note 14—Allowance for Current Expected Credit Loss (CECL)

ASU 2016-13 requires that an allowance for expected credit losses be recognized for certain financial assets that reflects the current expected credit loss over the financial asset’s contractual life. The valuation allowance considers the risk of loss, even if remote, and considers past events, current conditions and reasonable and supportable forecasts.

We are exposed to credit losses primarily through sale of products and services and notes receivable from third-parties. A counterparty’s ability to pay is assessed through a credit process that considers the payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness and other risks. We can require prepayment or collateral to mitigate credit risks.

30

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

We group our financial assets into pools of counterparties with similar risk characteristics for the purpose of determining the allowance for expected credit losses. Each reporting period, we assess whether a significant change in the risk of expected credit loss has occurred. Among the quantitative and qualitative factors considered in calculating our allowance for expected credit losses are historical financial data, including write-offs and allowances, current conditions, industry risk and current credit ratings. Financial assets will be written off in whole, or in part, when practical recovery efforts have been exhausted and no reasonable expectation of recovery exists. Subsequent recoveries of amounts previously written off are recorded as an increase to the allowance. We manage receivable pools using past due balances as a key credit quality indicator.

The following table summarizes changes in our allowance for expected credit losses:

	Accounts Receivable - Trade		Notes Receivable and Other
	(in thousands)
Balance at March 31, 2021	$	2,192	$	458
Change in provision for expected credit losses	88		—
Write-offs charged against the provision	(49)		—
Disposition of Sawtooth (see Note 15)	(4)		—
Balance at December 31, 2021	$	2,227	$	458

Note 15—Other Matters

Sale of Sawtooth

On June 18, 2021, we sold our approximately 71.5% interest in Sawtooth to a group of buyers for total consideration of $70.0 million less expenses of approximately $2.0 million. We recorded a loss of $60.1 million within loss on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations for the nine months ended December 31, 2021.

As this sale transaction did not represent a strategic shift that will have a major effect on our operations or financial results, operations related to this portion of our Liquids Logistics segment have not been classified as discontinued operations.

Note 16—Discontinued Operations

As previously disclosed, on September 30, 2019, we completed the sale of TransMontaigne Product Services, LLC (“TPSL”) to Trajectory Acquisition Company, LLC. On January 3, 2020, we completed the sale of our refined products business in the mid-continent region of the United States (“Mid-Con”) to a third-party. On March 30, 2020, we completed the sale of our gas blending business in the southeastern and eastern regions of the United States (“Gas Blending”) to another third-party. As the sale of each of these businesses represented strategic shifts, the results of operations and cash flows related to these businesses are classified as discontinued operations for the periods presented.

The following table summarizes the results of operations from discontinued operations for the periods indicated:

	Three Months Ended December 31,		Nine Months Ended December 31,
	2020		2020
	(in thousands)
Revenues	$	—	$	16,198
Cost of sales	106		16,535
Operating expenses	1		281
Loss on disposal or impairment of assets, net (1)	—		1,181
Loss from discontinued operations before taxes	(107)		(1,799)
Income tax benefit	—		53
Loss from discontinued operations, net of tax	$	(107)	$	(1,746)

(1)    Amount for the nine months ended December 31, 2020 includes a loss of $1.0 million on the sale of Gas Blending and a loss of $0.2 million on the sale of TPSL.

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and nine months ended December 31, 2021. 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 Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2021 (“Annual Report”) filed with the Securities and Exchange Commission on June 3, 2021.

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2021, our operations included three segments: Water Solutions, Crude Oil Logistics and Liquids Logistics. See Note 1 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of these businesses.

Consolidated Results of Operations

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Revenues	$	2,171,876	$	1,462,019	$	5,414,668	$	3,474,592
Cost of sales	1,950,321		1,278,879		4,800,707		2,920,816
Operating expenses	72,807		61,427		207,610		182,468
General and administrative expense	18,925		16,044		46,149		50,677
Depreciation and amortization	68,480		78,200		222,145		249,655
Loss on disposal or impairment of assets, net	12,233		373,776		93,463		391,752
Operating income (loss)	49,110		(346,307)		44,594		(320,776)
Equity in earnings of unconsolidated entities	119		344		765		1,134
Interest expense	(68,379)		(47,252)		(204,004)		(138,148)
Gain on early extinguishment of liabilities, net	9		11,190		1,131		44,292
Other income, net	24		440		2,003		3,060
Loss from continuing operations before income taxes	(19,117)		(381,585)		(155,511)		(410,438)
Income tax benefit	135		1,162		820		2,237
Loss from continuing operations	(18,982)		(380,423)		(154,691)		(408,201)
Loss from discontinued operations, net of tax	—		(107)		—		(1,746)
Net loss	(18,982)		(380,530)		(154,691)		(409,947)
Less: Net loss (income) attributable to noncontrolling interests	63		34		(705)		(185)
Net loss attributable to NGL Energy Partners LP	$	(18,919)	$	(380,496)	$	(155,396)	$	(410,132)

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 acquisitions, disposals and other transactions. Our results of operations for the three months and nine months ended December 31, 2021 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2022.

Recent Developments

Global Pandemic

The global spread of COVID-19 caused a global pandemic and worldwide containment and mitigation measures contributed to a massive economic slowdown and decreased demand for crude oil and refined products. This period of

32

unprecedented restrictions on travel and economic activity significantly reduced demand for refined products and all three of our segments were negatively impacted by the lower commodity price environment and reduced demand.

While many global and regional economies have reopened, the potential future limitations and impact of the ongoing COVID-19 pandemic, including emerging variants of the virus and renewed mitigation measures, on our business are still unknown at this time. Given the uncertain timing of a return of refined product demand to historical levels, the extent these events will have an impact on our results of operations is unclear. Crude oil prices have increased but future drilling and production plans are continually being assessed.

Seismic Activity

Induced seismic activity, associated with subsurface injection of produced water for disposal, has become a concern for certain state government agencies in several areas of the Permian Basin in which our Water Solutions business operates. To mitigate in these areas, we have been leading collaborative industry efforts with the relevant state regulatory agencies and other disposal operators. We have implemented voluntary strategic reductions in injected volumes at certain facilities, have temporarily shut in facilities, where appropriate, and are working with state regulatory agencies to collect and review data that will help derive appropriate and sustainable solutions. To date, due to the capacity within our integrated system in those areas, the diverse locations of our disposal facilities and the connectivity of our system, we have not been negatively impacted by these actions.

Acquisitions and Dispositions

We completed several acquisitions and dispositions during the nine months ended December 31, 2021 and fiscal year ended March 31, 2021. These transactions impact the comparability of our results of operations between our current and prior fiscal years.

On June 18, 2021, we sold our approximately 71.5% interest in Sawtooth Caverns, LLC (“Sawtooth”) to a group of buyers (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

In March 2021, we acquired the Ambassador pipeline, an approximately 225-mile natural gas liquids pipeline, which runs from the Kalkaska gas plant in Kalkaska County, Michigan to a termination point near Marysville in St. Clair County, Michigan. In December 2020, we sold certain permits, land and a saltwater disposal facility to a third-party.

Repurchases of Senior Unsecured Notes

During the three months ended December 31, 2021, we repurchased $20.0 million of the 7.5% senior unsecured notes due 2023 (“2023 Notes”).

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Segment Operating Results for the Three Months Ended December 31, 2021 and 2020

Water Solutions

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

	Three Months Ended December 31,
	2021		2020		Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Water disposal service fees	$	100,106	$	79,802	$	20,304
Sale of recovered crude oil	17,865		6,778		11,087
Recycled water	869		1,165		(296)
Other revenues	11,813		11,180		633
Total revenues	130,653		98,925		31,728
Expenses:
Cost of sales-excluding impact of derivatives	4,944		2,086		2,858
Derivative loss	86		1,194		(1,108)
Operating expenses	43,177		34,819		8,358
General and administrative expenses	1,783		1,645		138
Depreciation and amortization expense	50,815		53,327		(2,512)
Loss (gain) on disposal or impairment of assets, net	9,997		(9,967)		19,964
Total expenses	110,802		83,104		27,698
Segment operating income	$	19,851	$	15,821	$	4,030
Produced water processed (barrels per day)
Delaware Basin	1,551,621		1,216,096		335,525
Eagle Ford Basin	110,243		72,951		37,292
DJ Basin	159,332		96,383		62,949
Other Basins	18,351		26,532		(8,181)
Total	1,839,547		1,411,962		427,585
Recycled water (barrels per day)	52,854		95,903		(43,049)
Total Produced Water Processed and/or Sold (barrels per day)	1,892,401		1,507,865		384,536
Skim oil sold (barrels per day)	2,678		2,004		674
Service fees for produced water processed ($/barrel) (1)	$	0.58	$	0.61	$	(0.03)
Recovered crude oil for produced water processed ($/barrel) (1)	$	0.11	$	0.05	$	0.06
Operating expenses for produced water processed ($/barrel) (1)	$	0.26	$	0.27	$	(0.01)

(1)    Total produced water barrels processed during the three months ended December 31, 2021 and 2020 were 169,238,413 and 129,900,413, respectively.

Water Disposal Service Fee Revenues. The increase was due to an increase in produced water volumes processed as a result of increased crude oil production driven by higher crude oil prices and completion activity, primarily in the Delaware Basin. This was partially offset by lower service fees received per barrel due to higher volumes received in basins with lower fees, such as the Eagle Ford Basin, as well as increased volumes from customers with lower contracted fees.

Recovered Crude Oil Revenues. The increase was due primarily to higher volumes of skim oil sold due to increased produced water processed as well as higher crude oil prices realized.

Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers completion activities. The decrease was due primarily to the timing of our customers completions.

Other Revenues. Other revenues primarily include brackish non-potable water revenues, water pipeline revenues, land surface use revenues and solids disposal revenues. The increase was due primarily to higher sales of brackish non-potable water and pipeline revenues, driven by an increase in drilling and completion activity primarily in the Delaware Basin as well as our increased capacity to meet demand for these services, partially offset by lower solids disposal revenues.

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Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to costs related to the transfer of brackish non-potable water and recycled water to the purchaser as well as increased purchases of brackish non-potable water from third-parties to meet customer needs.

Derivative Loss. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the crude oil we expect to recover when processing the produced water and selling the recovered skim oil. During the three months ended December 31, 2021, we had $1.8 million of net unrealized losses on derivatives and $1.7 million of net realized gains on derivatives. During the three months ended December 31, 2020, we had $4.6 million of net realized gains on derivatives and $5.8 million of net unrealized losses on derivatives.

Operating and General and Administrative Expenses. The increase was due primarily to higher utility, royalty and chemical expenses as a result of the increase in produced water volumes processed. Utility and royalty expenses, which are two of our biggest variable expenses, were not impacted by the rise in inflation due to negotiating long-term utility contracts with fixed rates and royalty contracts with no escalation clauses. Severance taxes also increased due to the increase in revenue from recovered crude oil. The Partnership continues to see a decrease in its operating expenses per barrel of produced water processed due to continued focus on cost reduction and an increase in overall disposal volumes.

Depreciation and Amortization Expense. The decrease was due primarily to an impairment charge recorded during the three months ended March 31, 2021 to write down the value of an intangible asset which resulted in lower amortization expense during the three months ended December 31, 2021 as well as certain other long-term assets being fully amortized or impaired during the fiscal year ended March 31, 2021 and nine months ended December 31, 2021. These decreases were partially offset by the depreciation of newly developed facilities and infrastructure.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2021, we recorded a net loss of $14.3 million primarily related to the write-down of an inactive saltwater disposal facility and damaged equipment and wells at other facilities, abandonment of certain capital projects and the sale of certain other miscellaneous assets and a gain of $4.3 million on the sale of certain land and a landfill permit. During the three months ended December 31, 2020, we recorded a gain of $12.1 million related to the sale of certain permits, land and a saltwater disposal facility, and a net loss of $2.0 million primarily related to the abandonment of certain capital projects.

35

Crude Oil Logistics

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

	Three Months Ended December 31,
	2021		2020		Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	588,729	$	455,790	$	132,939
Crude oil transportation and other	20,979		31,326		(10,347)
Total revenues (1)	609,708		487,116		122,592
Expenses:
Cost of sales-excluding impact of derivatives	556,581		444,356		112,225
Derivative loss	2,455		6,404		(3,949)
Operating expenses	13,079		16,799		(3,720)
General and administrative expenses	1,874		1,985		(111)
Depreciation and amortization expense	12,166		16,513		(4,347)
Loss on disposal or impairment of assets, net	2,262		383,251		(380,989)
Total expenses	588,417		869,308		(280,891)
Segment operating income (loss)	$	21,291	$	(382,192)	$	403,483
Crude oil sold (barrels)	7,515		10,733		(3,218)
Crude oil transported on owned pipelines (barrels)	7,590		6,368		1,222
Crude oil storage capacity - owned and leased (barrels) (2)	5,232		5,239		(7)
Crude oil storage capacity leased to third parties (barrels) (2)	1,501		2,062		(561)
Crude oil inventory (barrels) (2)	1,295		1,019		276
Crude oil sold ($/barrel)	$	78.341	$	42.466	$	35.875
Cost per crude oil sold ($/barrel) (3)	$	74.063	$	41.401	$	32.662
Crude oil product margin ($/barrel) (3)	$	4.278	$	1.065	$	3.213

(1)    Revenues include $2.5 million and $1.8 million of intersegment sales during the three months ended December 31, 2021 and 2020, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

(2)    Information is presented as of December 31, 2021 and December 31, 2020, respectively.

(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The increase was due primarily to an increase in crude oil prices during the three months ended December 31, 2021, compared to the three months ended December 31, 2020. This was offset by the reduction in sale volumes, primarily due to lower production in the DJ Basin. We also had an increase in buy/sell transactions during the quarter ended December 31, 2021. 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. The revenues, cost of sales and volumes are netted for these transactions.

Crude Oil Transportation and Other Revenues. The decrease was primarily due to our Grand Mesa Pipeline, as revenues from third-parties decreased by $10.6 million during the three months ended December 31, 2021, compared to the three months ended December 31, 2020 due to the court approved rejection of the Extraction Oil & Gas, Inc. (“Extraction”) transportation agreement (as part of their bankruptcy) during the prior year quarter. In addition, revenue from the rental of storage also declined due to less capacity being leased to third parties. These declines were partially offset by increased barge transportation revenue as the number of charter days for our fleet increased over the same period as demand increased to pre-pandemic levels.

During the three months ended December 31, 2021, financial volumes on the Grand Mesa Pipeline averaged approximately 83,000 barrels per day, compared to approximately 69,000 barrels per day for the three months ended December 31, 2020 (volume amounts are from both internal and external parties). The increase was due primarily to the new supply agreement signed with Extraction after they exited bankruptcy.

Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in crude oil prices during the three months ended December 31, 2021, compared to the three months ended December 31, 2020.

36

Derivative Loss. Our cost of sales during the three months ended December 31, 2021 included $34.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $32.2 million of net unrealized gains on derivatives. Our cost of sales during the three months ended December 31, 2020 included $1.5 million of net realized gains on derivatives and $7.9 million of net unrealized losses on derivatives.

Crude Oil Product Margin. The increase was primarily due to higher crude oil prices as certain contracted rates with producers increased due to higher crude oil prices.

Operating and General and Administrative Expenses. The decrease was primarily related to the write off of a receivable from Extraction of $5.7 million related to deficiency volumes (see below) in the three months ended December 31, 2020. During the bankruptcy, Extraction continued to utilize the shipping services under the transportation contracts but only paid us for the actual volumes shipped and not for the difference between the minimum volume commitment specified under the contracts and the actual volumes shipped (“deficiency volumes”). This decrease was partially offset by an increase in utility expense of $1.4 million in the three months ended December 31, 2021 due to increased volumes on Grand Mesa and increased utility rates.

Depreciation and Amortization Expense. The decrease was due primarily to the reduction of amortization expense due to the impairment of certain intangible assets at the end of the prior year. This was offset by an increase in depreciation expense due to reducing the estimated useful lives of our railcars.

Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2021, we recorded a net loss of $2.2 million for an impairment due to damage caused by Hurricane Ida to one of our Gulf Coast terminals. During the three months ended December 31, 2020, we recorded a net loss of $145.8 million for the impairment of an intangible asset related to a rejected transportation agreement with Extraction and a net loss of $237.8 million for the impairment of goodwill.

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Liquids Logistics

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

	Three Months Ended December 31,
	2021		2020		Change
	(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)	$	503,383	$	286,990	$	216,393
Cost of sales-excluding impact of derivatives	493,388		283,442		209,946
Derivative loss	189		175		14
Product margin	9,806		3,373		6,433
Propane sales:
Revenues (1)	397,365		277,696		119,669
Cost of sales-excluding impact of derivatives	403,814		254,810		149,004
Derivative (gain) loss	(1,392)		4,542		(5,934)
Product (loss) margin	(5,057)		18,344		(23,401)
Butane sales:
Revenues (1)	296,844		193,378		103,466
Cost of sales-excluding impact of derivatives	272,450		167,449		105,001
Derivative (gain) loss	(5,959)		12,288		(18,247)
Product margin	30,353		13,641		16,712
Other product sales:
Revenues-excluding impact of derivatives (1)	228,541		114,985		113,556
Cost of sales-excluding impact of derivatives	213,654		105,357		108,297
Derivative loss (gain)	6,816		(3)		6,819
Product margin	8,071		9,631		(1,560)
Service revenues:
Revenues (1)	2,280		6,603		(4,323)
Cost of sales	193		312		(119)
Product margin	2,087		6,291		(4,204)
Expenses:
Operating expenses	16,551		9,809		6,742
General and administrative expenses	1,821		2,100		(279)
Depreciation and amortization expense	3,756		6,976		(3,220)
Gain on disposal or impairment of assets, net	(26)		(43)		17
Total expenses	22,102		18,842		3,260
Segment operating income	$	23,158	$	32,438	$	(9,280)

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	Three Months Ended December 31,
	2021		2020		Change
	(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3)	168,189		426,962		(258,773)
Refined products sold (gallons)	203,898		214,132		(10,234)
Refined products sold ($/gallon)	$	2.469	$	1.340	$	1.129
Cost per refined products sold ($/gallon) (4)	$	2.420	$	1.324	$	1.096
Refined products product margin ($/gallon) (4)	$	0.049	$	0.016	$	0.033
Refined products inventory (gallons) (2)	1,314		1,190		124
Propane sold (gallons)	294,282		381,590		(87,308)
Propane sold ($/gallon)	$	1.350	$	0.728	$	0.622
Cost per propane sold ($/gallon) (4)	$	1.372	$	0.668	$	0.704
Propane product (loss) margin ($/gallon) (4)	$	(0.022)	$	0.060	$	(0.082)
Propane inventory (gallons) (2)	125,235		128,568		(3,333)
Propane storage capacity leased to third parties (gallons) (2)(3)	—		53,947		(53,947)
Butane sold (gallons)	180,191		212,697		(32,506)
Butane sold ($/gallon)	$	1.647	$	0.909	$	0.738
Cost per butane sold ($/gallon) (4)	$	1.512	$	0.787	$	0.725
Butane product margin ($/gallon) (4)	$	0.135	$	0.122	$	0.013
Butane inventory (gallons) (2)	45,129		31,847		13,282
Butane storage capacity leased to third parties (gallons) (2)(3)	—		56,700		(56,700)
Other products sold (gallons)	99,915		122,645		(22,730)
Other products sold ($/gallon)	$	2.287	$	0.938	$	1.349
Cost per other products sold ($/gallon) (4)	$	2.138	$	0.859	$	1.279
Other products product margin ($/gallon) (4)	$	0.149	$	0.079	$	0.070
Other products inventory (gallons) (2)	23,491		21,326		2,165

(1)    Revenue includes $1.9 million of intersegment sales during the three months ended December 31, 2020 that is eliminated in our unaudited condensed consolidated statement of operations.

(2)    Information is presented as of December 31, 2021 and December 31, 2020, respectively.

(3)    Decrease from March 31, 2021 relates to the sale of Sawtooth on June 18, 2021 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

(4)    Cost and product margin per gallon excludes the impact of derivatives.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. Revenues and cost of sales, excluding the impact of derivatives, increased due to higher commodity prices, offset partially by a decrease in volumes due to the continued weakness in demand in certain geographical areas due to COVID-19 and tighter supply.

Refined Products Derivative Loss. Our refined products margin during the three months ended December 31, 2021 included a realized loss of $0.2 million and the three months ended December 31, 2020 included a realized loss of $0.2 million.

Refined Products product margins increased during the three months ended December 31, 2021 due to supply being short as a result of extended refinery downtime in certain of the markets in which we compete. These refineries were back online towards the end of December. This increase was partially offset by lower product demand in other areas due to the lingering effects of COVID-19 lockdowns.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were due to higher commodity prices. The increase in propane prices was the result of lower inventories and a strong export market due to the increase in international prices. This was partially offset by lower propane volumes sold driven by reduced demand due to unusually warm weather at the beginning of winter and the loss of two producer services agreements in the three months ended December 31, 2021 compared to the three months ended December 31, 2020.

Propane Derivative (Gain) Loss. Our wholesale propane cost of sales included $29.7 million of net unrealized losses on derivatives and $31.1 million of net realized gains on derivatives during the three months ended December 31, 2021. During

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the three months ended December 31, 2020, our cost of wholesale propane sales included $1.8 million of net unrealized losses on derivatives and $2.7 million of net realized losses on derivatives.

Propane product margins, excluding the impact of derivatives, decreased as a result of lower demand due to the warmer than normal start to winter and rapidly declining prices. We built our inventory for the winter heating season, particularly in September and October, but due to the warm start of the season the average price for November declined approximately $0.20 per gallon compared to October’s monthly average price and prices continued to decrease another $0.20 per gallon through the end of December.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were primarily due to an increase in commodity prices, which was the result of the strength in crude oil prices and increased global demand, which has led to a tightened supply market. The increase was partially offset by lower volume due to the tight supply market.

Butane Derivative (Gain) Loss. Our cost of butane sales during the three months ended December 31, 2021 included $12.9 million of net unrealized gains on derivatives and $6.9 million of net realized losses on derivatives. Our cost of butane sales included $5.6 million of net unrealized losses on derivatives and $6.6 million of net realized losses on derivatives during the three months ended December 31, 2020.

Butane product margins, excluding the impact of derivatives, increased due to a tight supply market, driven by an increase in demand for exports, which is driving favorable sales differentials.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to higher commodity prices and increased demand for biodiesel. This was partially offset by reduced natural gasoline volumes during the three months ended December 31, 2021 due to less product being available for shipment by railcars as more of the product is now shipped via third-party pipelines.

Other Products Derivative Loss (Gain). Our derivatives of other products included $0.1 million of net unrealized losses and $6.7 million of net realized losses on derivatives during the three months ended December 31, 2021. Our derivatives of other products during the three months ended December 31, 2020 included less than $0.1 million of net unrealized gains on derivatives and less than $0.1 million of net realized losses on derivatives.

Other product sales product margins during the three months ended December 31, 2021 decreased due to lower natural gasoline margins as a result of the tight supply. This decrease was partially offset by increased biodiesel margins due to securing favorable supply contracts in the Midwest and transporting the product for sale in more favorable markets.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease for the current quarter was due primarily to the disposition of Sawtooth in June 2021.

Operating and General and Administrative Expenses. The increase was primarily due to higher compensation partially offset by the disposition of Sawtooth in June 2021.

Depreciation and Amortization Expense. The decrease was primarily due to the disposition of Sawtooth and lower amortization expense due to certain intangible assets being fully amortized as of September 30, 2021.

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Corporate and Other

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

	Three Months Ended December 31,
	2021		2020		Change
	(in thousands)
Other revenues:
Revenues	$	—	$	314	$	(314)
Cost of sales	—		455		(455)
Loss	—		(141)		141
Expenses:
General and administrative expenses	13,447		10,314		3,133
Depreciation and amortization expense	1,743		1,384		359
Loss on disposal or impairment of assets, net	—		535		(535)
Total expenses	15,190		12,233		2,957
Operating loss	$	(15,190)	$	(12,374)	$	(2,816)

General and Administrative Expenses. The increase during the three months ended December 31, 2021 was due to increased incentive compensation and outside consulting fees, offset by lower legal expenses due to certain claims being settled.

Equity in Earnings of Unconsolidated Entities

The decrease in equity in earnings of $0.2 million during the three months ended December 31, 2021 was due primarily to lower earnings from certain membership interests related to specific land and water services operations.

Interest Expense

Interest expense includes interest charged on the asset-based revolving credit facility (“ABL Facility”), senior secured notes and senior unsecured notes, as well as amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of $21.1 million during the three months ended December 31, 2021 was primarily due to the issuance of the 2026 Senior Secured Notes (as defined herein) which resulted in us paying a higher interest rate. See Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Gain on Early Extinguishment of Liabilities, Net

During the three months ended December 31, 2021 and 2020, the net gain (inclusive of debt issuance costs written off) primarily relates to the early extinguishment of a portion of the outstanding senior unsecured notes. See Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Other Income, Net

Other income, net for the current quarter was consistent with the prior quarter.

Income Tax Benefit

Income tax benefit was $0.1 million during the three months ended December 31, 2021, compared to an income tax benefit of $1.2 million during the three months ended December 31, 2020. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The increase in the noncontrolling interest loss of less than $0.1 million during the three months ended December 31, 2021 was due primarily to higher income from certain recycling operations and water solutions operations, partially offset by a loss from operations of the Sawtooth joint venture during the three months ended December 31, 2020.

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Segment Operating Results for the Nine Months Ended December 31, 2021 and 2020

Water Solutions

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

	Nine Months Ended December 31,
	2021		2020		Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Water disposal service fees	$	293,291	$	232,348	$	60,943
Sale of recovered crude oil	48,848		16,532		32,316
Recycled water	7,207		2,066		5,141
Other revenues	47,743		24,722		23,021
Total revenues	397,089		275,668		121,421
Expenses:
Cost of sales-excluding impact of derivatives	20,892		2,458		18,434
Derivative loss	899		6,101		(5,202)
Operating expenses	125,667		105,505		20,162
General and administrative expenses	5,509		4,842		667
Depreciation and amortization expense	164,466		173,680		(9,214)
Loss (gain) on disposal or impairment of assets, net	19,450		(3,415)		22,865
Total expenses	336,883		289,171		47,712
Segment operating income (loss)	$	60,206	$	(13,503)	$	73,709
Produced water processed (barrels per day)
Delaware Basin	1,488,529		1,127,679		360,850
Eagle Ford Basin	99,298		83,151		16,147
DJ Basin	142,606		114,256		28,350
Other Basins	25,516		28,359		(2,843)
Total	1,755,949		1,353,445		402,504
Recycled water (barrels per day)	76,319		43,008		33,311
Total Produced Water Processed and/or Sold (barrels per day)	1,832,268		1,396,453		435,815
Skim oil sold (barrels per day)	2,667		1,771		896
Service fees for produced water processed ($/barrel) (1)	$	0.60	$	0.62	$	(0.02)
Recovered crude oil for produced water processed ($/barrel) (1)	$	0.10	$	0.04	$	0.06
Operating expenses for produced water processed ($/barrel) (1)	$	0.26	$	0.28	$	(0.02)

(1)    Total produced water barrels processed during the nine months ended December 31, 2021 and 2020 were 482,885,902 and 372,197,325, respectively.

Water Disposal Service Fee Revenues. The increase was due to an increase in produced water volumes processed as a result of increased crude oil production driven by higher crude oil prices and completion activity, primarily in the Delaware Basin. This was partially offset by lower service fees received per barrel due to higher volumes received in basins with lower fees, such as the Eagle Ford Basin, as well as increased volumes from customers with lower contracted fees.

Recovered Crude Oil Revenues. The increase was due primarily to higher volumes of skim oil sold due to increased produced water processed as well as higher crude oil prices realized. Additionally, an increase in the number of wells completed in our area of operations during the period with increased flowback activity resulted in higher skim oil volumes per barrel of produced water processed.

Recycled Water Revenues. The increase was due primarily to the increasing demand for water to be used in completions, driven by an increase in drilling and completion activity primarily in the Delaware Basin, and our customers transition from brackish non-potable water to recycled water.

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Other Revenues. The increase was due primarily to higher sales of brackish non-potable water and pipeline revenues, driven by an increase in drilling and completion activity primarily in the Delaware Basin as well as our increased capacity to meet demand for these services, and higher land surface use fees and sales of caliche due to increased producer activity.

Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to costs related to the transfer of brackish non-potable water and recycled water to the purchaser as well as increased purchases of brackish non-potable water from third-parties to meet customer needs.

Derivative Loss. During the nine months ended December 31, 2021, we had $6.8 million of net unrealized losses on derivatives and $5.9 million of net realized gains on derivatives. During the nine months ended December 31, 2020, we had $17.4 million of net realized gains on derivatives and $23.5 million of net unrealized losses on derivatives.

Operating and General and Administrative Expenses. The increase was due primarily to higher utility, royalty and chemical expenses as a result of the increase in produced water volumes processed. Utility and royalty expenses, which are two of our biggest variable expenses, were not impacted by the rise in inflation due to negotiating long-term utility contracts with fixed rates and royalty contracts with no escalation clauses. Severance taxes also increased due to the increase in revenue from recovered crude oil. The Partnership continues to see a decrease in its operating expenses per barrel of produced water processed due to continued focus on cost reduction and an increase in overall disposal volumes.

Depreciation and Amortization Expense. The decrease was due primarily to an impairment charge recorded during the three months ended March 31, 2021 to write down the value of an intangible asset which resulted in lower amortization expense during the nine months ended December 31, 2021 as well as certain other long-term assets being fully amortized or impaired during the fiscal year ended March 31, 2021 and nine months ended December 31, 2021. These decreases were partially offset by the depreciation of newly developed facilities and infrastructure.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2021, we recorded a net loss of $23.7 million primarily related to the write-down of an inactive saltwater disposal facility and damaged equipment and wells at other facilities, abandonment of certain capital projects and the sale of certain other miscellaneous assets and a gain of $4.3 million on the sale of certain land and a landfill permit. During the nine months ended December 31, 2020, we recorded a gain of $12.1 million related to the sale of certain permits, land and a saltwater disposal facility, and a net loss of $8.7 million primarily related to the write-down of retired equipment and the abandonment of certain capital projects.

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Crude Oil Logistics

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

	Nine Months Ended December 31,
	2021		2020		Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	1,660,225	$	1,104,692	$	555,533
Crude oil transportation and other	62,606		127,808		(65,202)
Total revenues (1)	1,722,831		1,232,500		490,331
Expenses:
Cost of sales-excluding impact of derivatives	1,557,202		1,025,478		531,724
Derivative loss	41,849		32,114		9,735
Operating expenses	40,862		44,566		(3,704)
General and administrative expenses	5,742		6,044		(302)
Depreciation and amortization expense	37,029		50,540		(13,511)
Loss on disposal or impairment of assets, net	2,206		384,391		(382,185)
Total expenses	1,684,890		1,543,133		141,757
Segment operating income (loss)	$	37,941	$	(310,633)	$	348,574
Crude oil sold (barrels)	23,027		30,203		(7,176)
Crude oil transported on owned pipelines (barrels)	21,961		26,836		(4,875)
Crude oil storage capacity - owned and leased (barrels) (2)	5,232		5,239		(7)
Crude oil storage capacity leased to third parties (barrels) (2)	1,501		2,062		(561)
Crude oil inventory (barrels) (2)	1,295		1,019		276
Crude oil sold ($/barrel)	$	72.099	$	36.576	$	35.523
Cost per crude oil sold ($/barrel) (3)	$	67.625	$	33.953	$	33.672
Crude oil product margin ($/barrel) (3)	$	4.474	$	2.623	$	1.851

(1)    Revenues include $7.2 million and $4.3 million of intersegment sales during the nine months ended December 31, 2021 and 2020, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

(2)    Information is presented as of December 31, 2021 and December 31, 2020, respectively.

(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The increase was due primarily to an increase in crude oil prices during the nine months ended December 31, 2021, compared to the nine months ended December 31, 2020. This was offset by a reduction in sales volumes, primarily due to lower production in the DJ Basin. We also had an increase in buy/sell transactions during the nine months ended December 31, 2021, compared to the nine months ended December 31, 2020.

Crude Oil Transportation and Other Revenues. The decrease was primarily due to our Grand Mesa Pipeline, as revenues from third-parties decreased by $65.7 million during the nine months ended December 31, 2021, compared to the nine months ended December 31, 2020. During the nine months ended December 31, 2021, financial volumes on the Grand Mesa Pipeline averaged approximately 80,000 barrels per day, compared to 103,000 barrels per day for the nine months ended December 31, 2020 (volume amounts are from both internal and external parties). The decline was primarily due to the court approved rejection of the Extraction transportation agreement (as part of their bankruptcy) as well as decreased production in the DJ Basin.

Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in crude oil prices during the nine months ended December 31, 2021, compared to the nine months ended December 31, 2020.

Derivative Loss. Our cost of sales during the nine months ended December 31, 2021 included $95.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $53.8 million of net unrealized gains on derivatives. Our cost of sales during the nine months ended December 31, 2020 included $12.9 million of net realized losses on derivatives and $19.2 million of net unrealized losses on derivatives.

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Crude Oil Product Margin. The increase was primarily due to higher crude oil prices as certain contracted rates with producers increased due to higher crude oil prices.

Operating and General and Administrative Expenses. The decrease was primarily related to the write off a receivable related to deficiency volumes from Extraction of $5.7 million during the nine months ended December 31, 2020. The decrease was offset by an increase in utility expenses due to increased volumes on Grand Mesa and increased utility rates, as well as increased business insurance due to policy rate increases for the nine months ended December 31, 2021

Depreciation and Amortization Expense. The decrease was due primarily to the reduction of amortization expense due to the impairment of certain intangible assets at the end of the prior year. This was offset by an increase in depreciation expense due to reducing the estimated useful lives of our railcars.

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2021, we recorded a net loss of $2.2 million for an impairment due to damage caused by Hurricane Ida to one of our Gulf Coast terminals. During the nine months ended December 31, 2020, we recorded a net loss of $145.8 million for the impairment of an intangible asset related to a rejected transportation agreement with Extraction and a net loss of $237.8 million for the impairment of goodwill.

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Liquids Logistics

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

	Nine Months Ended December 31,
	2021		2020		Change
	(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)	$	1,340,824	$	786,472	$	554,352
Cost of sales-excluding impact of derivatives	1,324,587		775,400		549,187
Derivative loss	1,309		580		729
Product margin	14,928		10,492		4,436
Propane sales:
Revenues (1)	778,308		537,183		241,125
Cost of sales-excluding impact of derivatives	771,116		493,588		277,528
Derivative gain	(26,221)		(1,457)		(24,764)
Product margin	33,413		45,052		(11,639)
Butane sales:
Revenues (1)	583,080		339,025		244,055
Cost of sales-excluding impact of derivatives	540,607		302,116		238,491
Derivative loss	15,554		18,765		(3,211)
Product margin	26,919		18,144		8,775
Other product sales:
Revenues-excluding impact of derivatives (1)	570,878		284,929		285,949
Cost of sales-excluding impact of derivatives	535,203		269,312		265,891
Derivative loss (gain)	9,484		(941)		10,425
Product margin	26,191		16,558		9,633
Service revenues:
Revenues (1)	14,583		25,202		(10,619)
Cost of sales	1,151		3,268		(2,117)
Product margin	13,432		21,934		(8,502)
Expenses:
Operating expenses	41,081		32,397		8,684
General and administrative expenses	5,376		6,283		(907)
Depreciation and amortization expense	15,409		22,158		(6,749)
Loss on disposal or impairment of assets, net	71,807		4		71,803
Total expenses	133,673		60,842		72,831
Segment operating (loss) income	$	(18,790)	$	51,338	$	(70,128)

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	Nine Months Ended December 31,
	2021		2020		Change
	(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3)	168,189		426,962		(258,773)
Refined products sold (gallons)	586,136		646,349		(60,213)
Refined products sold ($/gallon)	$	2.288	$	1.217	$	1.071
Cost per refined products sold ($/gallon) (4)	$	2.260	$	1.200	$	1.060
Refined products product margin ($/gallon) (4)	$	0.028	$	0.017	$	0.011
Refined products inventory (gallons) (2)	1,314		1,190		124
Propane sold (gallons)	644,883		886,572		(241,689)
Propane sold ($/gallon)	$	1.207	$	0.606	$	0.601
Cost per propane sold ($/gallon) (4)	$	1.196	$	0.557	$	0.639
Propane product margin ($/gallon) (4)	$	0.011	$	0.049	$	(0.038)
Propane inventory (gallons) (2)	125,235		128,568		(3,333)
Propane storage capacity leased to third parties (gallons) (2)(3)	—		53,947		(53,947)
Butane sold (gallons)	427,646		475,655		(48,009)
Butane sold ($/gallon)	$	1.363	$	0.713	$	0.650
Cost per butane sold ($/gallon) (4)	$	1.264	$	0.635	$	0.629
Butane product margin ($/gallon) (4)	$	0.099	$	0.078	$	0.021
Butane inventory (gallons) (2)	45,129		31,847		13,282
Butane storage capacity leased to third parties (gallons) (2)(3)	—		56,700		(56,700)
Other products sold (gallons)	290,078		351,591		(61,513)
Other products sold ($/gallon)	$	1.968	$	0.810	$	1.158
Cost per other products sold ($/gallon) (4)	$	1.845	$	0.766	$	1.079
Other products product margin ($/gallon) (4)	$	0.123	$	0.044	$	0.079
Other products inventory (gallons) (2)	23,491		21,326		2,165

(1)    Revenues include $1.3 million and $3.4 million of intersegment sales during the nine months ended December 31, 2021 and 2020, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

(2)    Information is presented as of December 31, 2021 and December 31, 2020, respectively.

(3)    Decrease from March 31, 2021 relates to the sale of Sawtooth on June 18, 2021 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

(4)    Cost and product margin per gallon excludes the impact of derivatives.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to an increase in refined products price. This was offset by a reduction in volumes sold due to the continued weakness in demand in certain geographical areas due to COVID-19 and tighter supply.

Refined Products Derivative Loss. Our refined products margin during the nine months ended December 31, 2021 included a realized loss of $1.3 million and the nine months ended December 31, 2020 included a realized loss of $0.6 million.

Refined Products product margins per gallon of refined products sold for the nine months ended December 31, 2021 increased from the prior year nine months ended December 31, 2020 primarily due to supply being short as a result of extended refinery downtime in certain of the markets in which we compete during the three months ended December 31, 2021, offset by increased competition from refineries.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were due to higher commodity prices. The increase in propane prices was the result of lower inventories and a strong export market due to the increase in international prices. This was partially offset by lower propane volumes sold driven by reduced demand due to unusually warm weather at the beginning of winter, warmer than normal autumn temperatures which resulted in lower product demand for crop drying, reduced volumes due to the loss of two producer services agreements, as well as

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backwardation in the propane market and deferred customer purchases in the nine months ended December 31, 2021 compared to the nine months ended December 31, 2020.

Propane Derivative Gain. Our wholesale propane cost of sales included $4.0 million of net unrealized gains on derivatives and $22.3 million of net realized gains on derivatives during the nine months ended December 31, 2021. During the nine months ended December 31, 2020, our cost of wholesale propane sales included $1.8 million of net unrealized losses on derivatives and $3.2 million of net realized gains on derivatives.

Propane product margins, excluding the impact of derivatives, decreased as a result of lower demand due to the warmer than normal start to winter and rapidly declining prices. We built our inventory for the winter heating season, particularly in September and October, but due to the warm start of the season the average price for November declined approximately $0.20 per gallon compared to October’s monthly average price and prices continued to decrease through the end of December.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were due primarily to higher commodity prices. This was partially offset by a volume decrease due to a tight supply market as a result of decreased refinery runs and an increase in demand for exports.

Butane Derivative Loss. Our cost of butane sales during the nine months ended December 31, 2021 included $2.6 million of net unrealized losses on derivatives and $12.9 million of net realized losses on derivatives. Our cost of butane sales included $3.7 million of net unrealized losses on derivatives and $15.1 million of net realized losses on derivatives during the nine months ended December 31, 2020.

Butane product margins per gallon of butane sold were higher during the nine months ended December 31, 2021 than during the nine months ended December 31, 2020 due primarily due to a tight supply market, driven by an increase in demand for exports and increase in blending demand, which are driving favorable sales differentials.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to higher commodity prices. This was partially offset by reduced natural gasoline volumes during the nine months ended December 31, 2021 due to less natural gas production resulting in a tight supply market.

Other Products Derivatives Loss (Gain). Our derivatives of other products included less than $0.1 million of net unrealized losses on derivatives and $9.5 million of net realized losses on derivatives during the nine months ended December 31, 2021. Our derivatives of other products during the nine months ended December 31, 2020 included $0.5 million of net unrealized gains on derivatives and $0.4 million of net realized gains on derivatives.

Other product sales product margins during the nine months ended December 31, 2021 increased due to an increase in biodiesel and biodiesel renewable identification number market prices, as well as securing favorable biodiesel supply contracts in the Midwest and transporting the product for sale in more favorable markets. The increase was partially offset by lower natural gasoline volumes due to less product being available for shipment by railcars as more of the product is now shipped via third-party pipelines.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the nine months ended December 31, 2021 was due to the disposition of Sawtooth in June 2021 as well as less throughput in certain of our propane and butane terminals.

Operating and General and Administrative Expenses. The increase was primarily due to higher compensation, travel and entertainment and bad debt expense, partially offset by the disposition of Sawtooth in June 2021.

Depreciation and Amortization Expense. The decrease was primarily due to the disposition of Sawtooth and lower amortization expense due to certain intangible assets being fully amortized as of September 30, 2021.

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2021, we recorded a net loss of $60.1 million related to the sale of Sawtooth (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report for further discussion) and a net loss of $11.8 million related to the sale of another terminal during the three months ended September 30, 2021. During the nine months ended December 31, 2020, we recorded a net loss of less than $0.1 million related to the retirement of certain assets.

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Corporate and Other

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

	Nine Months Ended December 31,
	2021		2020		Change
	(in thousands)
Other revenues:
Revenues	$	—	$	942	$	(942)
Cost of sales	—		1,363		(1,363)
Loss	—		(421)		421
Expenses:
General and administrative expenses	29,522		33,508		(3,986)
Depreciation and amortization expense	5,241		3,277		1,964
Loss on disposal or impairment of assets, net	—		10,772		(10,772)
Total expenses	34,763		47,557		(12,794)
Operating loss	$	(34,763)	$	(47,978)	$	13,215

General and Administrative Expenses. The decrease during the nine months ended December 31, 2021 was due primarily to lower compensation and legal expenses, offset by increased consulting fees. Compensation expense decreased due to lower equity-based compensation and due to the reversal of an incentive compensation accrual, offset by increased incentive compensation during the current year. Legal expense decreased due to certain claims being settled, in particular our claims related to the bankruptcy of Extraction.

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2020, we recorded a net loss of $10.8 million, which was due to the write-off of a loan receivable made to a third party for the construction of a natural gas liquids loading/unloading facility.

Equity in Earnings of Unconsolidated Entities

The decrease in equity in earnings of $0.4 million during the nine months ended December 31, 2021 was due primarily to lower earnings from certain membership interests related to specific land and water services operations.

Interest Expense

Interest expense includes interest charged on the ABL Facility, senior secured notes and senior unsecured notes, as well as amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of $65.9 million during the nine months ended December 31, 2021 was primarily due to the issuance of the 2026 Senior Secured Notes which resulted in us paying a higher interest rate. See Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Gain on Early Extinguishment of Liabilities, Net

During the nine months ended December 31, 2021 and 2020, the net gain (inclusive of debt issuance costs written off) primarily relates to the early extinguishment of a portion of the outstanding senior unsecured notes, partially offset by a loss on the early extinguishment of the Sawtooth credit agreement. See Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Other Income, Net

The decrease in other income, net of $1.1 million during the nine months ended December 31, 2021 was due primarily to proceeds received from a litigation settlement during the nine months ended December 31, 2020.

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Income Tax Benefit

Income tax benefit was $0.8 million during the nine months ended December 31, 2021, compared to an income tax benefit of $2.2 million during the nine months ended December 31, 2020. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests

The increase in noncontrolling interest income of $0.5 million during the nine months ended December 31, 2021 was due primarily to higher income from certain recycling operations and water solutions operations, partially offset by a lower loss from operations of the Sawtooth joint venture primarily due to the sale of Sawtooth in June 2021.

Non-GAAP Financial Measures

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

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or net realizable value adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, equity-based compensation expense, acquisition expense, revaluation of liabilities, certain legal settlements and other. We also include in Adjusted EBITDA certain inventory valuation adjustments related to TransMontaigne Product Services, LLC (“TPSL”), our refined products business in the mid-continent region of the United States (“Mid-Con”), and our gas blending business in the southeastern and eastern regions of the United States (“Gas Blending”), which are included in discontinued operations, and certain refined products businesses within our Liquids Logistics segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered as alternatives to net loss, loss from continuing operations 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 certain businesses within our Liquids Logistics 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 certain businesses within our Liquids Logistics segment. The primary hedging strategy of these businesses 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 cover extended periods of time. The “inventory valuation adjustment” row in the reconciliation table reflects the difference between the market value of the inventory of these businesses at the balance sheet date and its cost, adjusted for the impact of seasonal market movements related to our base inventory and the related hedge. We include this in Adjusted EBITDA because the unrealized gains and losses associated with derivative contracts associated with the inventory of this segment, which are intended primarily to hedge inventory holding risk and are included in net income, also affect Adjusted EBITDA. In our Crude Oil Logistics segment, we purchase certain crude oil barrels using the West Texas Intermediate (“WTI”) calendar month average (“CMA”) price and sell the crude oil barrels using the WTI CMA price plus the Argus CMA Differential Roll Component (“CMA Differential Roll”) per our contracts. To eliminate the volatility of the CMA Differential Roll, we entered into derivative instrument positions in January 2021 to secure a margin of approximately $0.20 per barrel on 1.5 million barrels per month from May 2021 through December 2023. Due to the nature of these positions, the cash flow and earnings recognized on a GAAP basis will differ from period to period depending on the current crude oil price and future estimated crude oil price which are valued utilizing third-party market quoted prices. We are recognizing in Adjusted EBITDA the gains and losses from the derivative instrument positions entered into in January 2021 to properly align with the physical margin we are hedging each month through the term of this transaction. This representation aligns with management’s evaluation of the transaction.

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Net loss	$	(18,982)	$	(380,530)	$	(154,691)	$	(409,947)
Less: Net loss (income) attributable to noncontrolling interests	63		34		(705)		(185)
Net loss attributable to NGL Energy Partners LP	(18,919)		(380,496)		(155,396)		(410,132)
Interest expense	68,395		47,253		204,037		138,159
Income tax benefit	(135)		(1,163)		(820)		(2,291)
Depreciation and amortization	68,452		77,531		221,352		247,555
EBITDA	117,793		(256,875)		269,173		(26,709)
Net unrealized (gains) losses on derivatives	(13,500)		16,529		(48,254)		47,657
CMA Differential Roll net losses (gains) (1)	23,872		—		60,987		—
Inventory valuation adjustment (2)	1,145		(786)		1,912		1,393
Lower of cost or net realizable value adjustments	2,921		321		2,636		(33,213)
Loss on disposal or impairment of assets, net	12,035		373,777		93,268		392,924
Gain on early extinguishment of liabilities, net	(9)		(11,190)		(1,168)		(44,292)
Equity-based compensation expense (3)	749		1,120		(1,044)		5,678
Acquisition expense (4)	(36)		589		67		915
Other (5)	2,770		1,448		7,525		9,049
Adjusted EBITDA	$	147,740	$	124,933	$	385,102	$	353,402
Adjusted EBITDA - Discontinued Operations (6)	$	—	$	(107)	$	—	$	(591)
Adjusted EBITDA - Continuing Operations	$	147,740	$	125,040	$	385,102	$	353,993

(1)    Adjustment to align, within Adjusted EBITDA, the net gains and losses of the Partnership’s CMA Differential Roll derivative instruments positions with the physical margin being hedged. See “Non-GAAP Financial Measures” section above for a further discussion.

(2)    Amount reflects the difference between the market value of the inventory at the balance sheet date and its cost, adjusted for the impact of seasonal market movements related to our base inventory and the related hedge. See “Non-GAAP Financial Measures” section above for a further discussion.

(3)    Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 8 to our unaudited condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

(4)    Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions.

(5)    Amounts for the three months and nine months ended December 31, 2021 and 2020 represent non-cash operating expenses related to our Grand Mesa Pipeline, unrealized losses on marketable securities and accretion expense for asset retirement obligations.

(6)    Amounts include the operations of TPSL, Gas Blending and Mid-Con.

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	68,452	$	77,531	$	221,352	$	247,555
Intangible asset amortization recorded to cost of sales	(69)		(77)		(213)		(230)
Depreciation and amortization of unconsolidated entities	(187)		(199)		(545)		(542)
Depreciation and amortization attributable to noncontrolling interests	284		945		1,551		2,872
Depreciation and amortization per unaudited condensed consolidated statements of operations	$	68,480	$	78,200	$	222,145	$	249,655

	Nine Months Ended December 31,
	2021		2020
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	221,352	$	247,555
Amortization of debt issuance costs recorded to interest expense	12,814		9,984
Amortization of royalty expense recorded to operating expense	185		185
Depreciation and amortization of unconsolidated entities	(545)		(542)
Depreciation and amortization attributable to noncontrolling interests	1,551		2,872
Depreciation and amortization per unaudited condensed consolidated statements of cash flows	$	235,357	$	260,054

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2021		2020		2021		2020
	(in thousands)
Interest expense per EBITDA table	$	68,395	$	47,253	$	204,037	$	138,159
Interest expense attributable to noncontrolling interests	(1)		16		16		42
Interest expense attributable to unconsolidated entities	(15)		(17)		(49)		(53)
Interest expense per unaudited condensed consolidated statements of operations	$	68,379	$	47,252	$	204,004	$	138,148

The following table summarizes additional amounts attributable to discontinued operations in the EBITDA table above for the periods indicated:

	Three Months Ended December 31,		Nine Months Ended December 31,
	2020		2020
	(in thousands)
Income tax benefit	$	—	$	(53)
Inventory valuation adjustment	$	16	$	(6)
Lower of cost or net realizable value adjustments	$	(15)	$	6
Loss on disposal or impairment of assets, net	$	—	$	1,181

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The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated.

	Three Months Ended December 31, 2021
	Water Solutions		Crude Oil Logistics		Liquids Logistics		Corporate and Other		Consolidated
	(in thousands)
Operating income (loss)	$	19,851	$	21,291	$	23,158	$	(15,190)	$	49,110
Depreciation and amortization	50,815		12,166		3,756		1,743		68,480
Amortization recorded to cost of sales	—		—		69		—		69
Net unrealized losses (gains) on derivatives	1,758		(32,201)		16,943		—		(13,500)
CMA Differential Roll net losses (gains)	—		23,872		—		—		23,872
Inventory valuation adjustment	—		—		1,145		—		1,145
Lower of cost or net realizable value adjustments	—		—		2,921		—		2,921
Loss (gain) on disposal or impairment of assets, net	9,997		2,262		(26)		—		12,233
Equity-based compensation expense	—		—		—		749		749
Acquisition expense	4		—		—		(40)		(36)
Other (expense) income, net	(6)		—		(31)		61		24
Adjusted EBITDA attributable to unconsolidated entities	384		—		10		(70)		324
Adjusted EBITDA attributable to noncontrolling interest	(419)		—		(3)		—		(422)
Other	360		2,374		37		—		2,771
Adjusted EBITDA	$	82,744	$	29,764	$	47,979	$	(12,747)	$	147,740

	Three Months Ended December 31, 2020
	Water Solutions		Crude Oil Logistics		Liquids Logistics		Corporate and Other		Continuing Operations		Discontinued Operations (TPSL, Mid-Con, Gas Blending)		Consolidated
	(in thousands)
Operating income (loss)	$	15,821	$	(382,192)	$	32,438	$	(12,374)	$	(346,307)	$	—	$	(346,307)
Depreciation and amortization	53,327		16,513		6,976		1,384		78,200		—		78,200
Amortization recorded to cost of sales	—		—		77		—		77		—		77
Net unrealized losses on derivatives	5,800		7,878		2,851		—		16,529		—		16,529
Inventory valuation adjustment	—		—		(802)		—		(802)		—		(802)
Lower of cost or net realizable value adjustments	—		(166)		502		—		336		—		336
(Gain) loss on disposal or impairment of assets, net	(9,967)		383,251		(43)		535		373,776		—		373,776
Equity-based compensation expense	—		—		—		1,120		1,120		—		1,120
Acquisition expense	4		—		—		585		589		—		589
Other income, net	1		2		341		96		440		—		440
Adjusted EBITDA attributable to unconsolidated entities	573		—		3		(16)		560		—		560
Adjusted EBITDA attributable to noncontrolling interest	(389)		—		(544)		—		(933)		—		(933)
Other	384		1,046		25		—		1,455		—		1,455
Discontinued operations	—		—		—		—		—		(107)		(107)
Adjusted EBITDA	$	65,554	$	26,332	$	41,824	$	(8,670)	$	125,040	$	(107)	$	124,933

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	Nine Months Ended December 31, 2021
	Water Solutions		Crude Oil Logistics		Liquids Logistics		Corporate and Other		Consolidated
	(in thousands)
Operating income (loss)	$	60,206	$	37,941	$	(18,790)	$	(34,763)	$	44,594
Depreciation and amortization	164,466		37,029		15,409		5,241		222,145
Amortization recorded to cost of sales	—		—		213		—		213
Net unrealized losses (gains) on derivatives	6,845		(53,808)		(1,291)		—		(48,254)
CMA Differential Roll net losses (gains)	—		60,987		—		—		60,987
Inventory valuation adjustment	—		—		1,912		—		1,912
Lower of cost or net realizable value adjustments	—		(11)		2,647		—		2,636
Loss on disposal or impairment of assets, net	19,450		2,206		71,807		—		93,463
Equity-based compensation expense	—		—		—		(1,044)		(1,044)
Acquisition expense	4		—		—		63		67
Other income, net	616		350		627		410		2,003
Adjusted EBITDA attributable to unconsolidated entities	1,559		—		(9)		(190)		1,360
Adjusted EBITDA attributable to noncontrolling interest	(1,987)		—		(529)		—		(2,516)
Other	520		6,994		22		—		7,536
Adjusted EBITDA	$	251,679	$	91,688	$	72,018	$	(30,283)	$	385,102

	Nine Months Ended December 31, 2020
	Water Solutions		Crude Oil Logistics		Liquids Logistics		Corporate and Other		Continuing Operations		Discontinued Operations (TPSL, Mid-Con, Gas Blending)		Consolidated
	(in thousands)
Operating (loss) income	$	(13,503)	$	(310,633)	$	51,338	$	(47,978)	$	(320,776)	$	—	$	(320,776)
Depreciation and amortization	173,680		50,540		22,158		3,277		249,655		—		249,655
Amortization recorded to cost of sales	—		—		230		—		230		—		230
Net unrealized losses on derivatives	23,525		19,199		4,933		—		47,657		—		47,657
Inventory valuation adjustment	—		—		1,399		—		1,399		—		1,399
Lower of cost or net realizable value adjustments	—		(29,245)		(3,974)		—		(33,219)		—		(33,219)
(Gain) loss on disposal or impairment of assets, net	(3,415)		384,391		4		10,772		391,752		—		391,752
Equity-based compensation expense	—		—		—		5,678		5,678		—		5,678
Acquisition expense	17		—		—		898		915		—		915
Other income, net	259		1,515		1,004		282		3,060		—		3,060
Adjusted EBITDA attributable to unconsolidated entities	1,883		—		(11)		(143)		1,729		—		1,729
Adjusted EBITDA attributable to noncontrolling interest	(1,317)		—		(1,816)		—		(3,133)		—		(3,133)
Intersegment transactions (1)	—		—		(27)		—		(27)		—		(27)
Other	2,398		6,600		75		—		9,073		—		9,073
Discontinued operations	—		—		—		—		—		(591)		(591)
Adjusted EBITDA	$	183,527	$	122,367	$	75,313	$	(27,214)	$	353,993	$	(591)	$	353,402

(1)    Amount reflects the transactions with TPSL, Mid-Con and Gas Blending that are eliminated in consolidation.

Liquidity, Sources of Capital and Capital Resource Activities

General

Our principal sources of liquidity and capital resource requirements are the cash flows from our operations, borrowings under our ABL Facility, debt issuances and the issuance of common and preferred units. We expect our primary cash outflows to be related to capital expenditures, interest and repayment of debt maturities.

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We believe that our anticipated cash flows from operations and the borrowing capacity under our ABL Facility will be sufficient to meet our liquidity needs. Our borrowing needs vary during the year due in part to the seasonal nature of certain businesses within our Liquids Logistics segment. 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 butane blending and heating seasons. Our working capital borrowing needs generally decline during the period of January through March, when the cash inflows from our Liquids Logistics segment are the greatest.

Cash Management

We manage cash by utilizing a centralized cash management program that concentrates the cash assets of our operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. All of our wholly-owned operating subsidiaries participate in this program. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Short-Term Liquidity

Our principal sources of short-term liquidity consist of cash generated from operating activities and borrowings under our $500.0 million ABL Facility, which we believe will provide liquidity to operate our business and manage our working capital requirements. We currently anticipate to have minimal needs for acquisitions or expansion projects and expect to fund these items through cash flows from operations, acquisition specific financing transactions or borrowings under the ABL Facility.

As of December 31, 2021, our current assets exceeded our current liabilities by approximately $321.4 million.

For additional information related to our ABL Facility, see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Cash Flows

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

	Nine Months Ended December 31,
Cash Flows Provided by (Used in):	2021		2020
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	224,457	$	270,226
Changes in operating assets and liabilities	(197,546)		(82,912)
Operating activities-continuing operations	$	26,911	$	187,314
Investing activities-continuing operations	$	(96,501)	$	(150,966)
Financing activities-continuing operations	$	70,217	$	(48,115)

Operating Activities-Continuing Operations. The seasonality of our Liquids Logistics business has a significant effect on our cash flows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories. In our Liquids Logistics business, we typically experience operating losses or lower operating income during our first and second quarters, or the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming butane blending and heating seasons, which generally begin in late fall, under normal demand conditions, and run through February or March. We borrow under the revolving credit facility to supplement our operating cash flows during the periods in which we are building inventory. Our operations, and as a result our cash flows, are also impacted by positive and negative movements in commodity prices, which cause fluctuations in the value of inventory, accounts receivable and payables, due to increases and decreases in revenues and cost of sales. The decrease in net cash provided by operating activities during the nine months ended December 31, 2021 was due primarily to fluctuations in the value of accounts receivable and accounts payable and increased inventory valuations during the nine months ended December 31, 2021.

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Investing Activities-Continuing Operations. Net cash used in investing activities was $96.5 million during the nine months ended December 31, 2021, compared to net cash used in investing activities of $151.0 million during the nine months ended December 31, 2020. The decrease in net cash used in investing activities was due primarily to:

•net proceeds (gross cash proceeds less the amount of cash sold, excluding accrued expenses) of $63.5 million from the sale of our interest in Sawtooth in June 2021 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report); and

•a decrease in capital expenditures from $151.6 million (includes payment of amounts accrued as of March 31, 2020) during the nine months ended December 31, 2020 to $107.5 million (includes payment of amounts accrued as of March 31, 2021) during the nine months ended December 31, 2021 due primarily to fewer expansion projects in our Water Solutions segment.

These decreases in net cash used in investing activities were partially offset by:

•total proceeds of $43.2 million from the sale of certain permits, land and a saltwater disposal facility to a third-party during the nine months ended December 31, 2020; and

•a $20.2 million increase in payments to settle derivatives.

Financing Activities-Continuing Operations. Net cash provided by financing activities was $70.2 million during the nine months ended December 31, 2021, compared to net cash used in financing activities of $48.1 million during the nine months ended December 31, 2020. The increase in net cash provided by financing activities was due primarily to:

•a decrease of $120.7 million in distributions paid to our general partners and common unitholders, preferred unitholders and noncontrolling interest owners during the nine months ended December 31, 2021 due primarily to the reduction and subsequent suspension of the quarterly common unit and preferred unit distributions;

•$93.4 million in contingent consideration payments during the nine months ended December 31, 2020 due to installment payments related to the Mesquite Disposals Unlimited, LLC acquisition; and

•a decrease of $14.9 million paid in cash to repurchase a portion of our senior unsecured notes during the nine months ended December 31, 2021.

These increases in net cash provided by financing activities were partially offset by:

•a decrease of $59.0 million in borrowings on the revolving credit facilities (net of repayments) during the nine months ended December 31, 2021; and

•proceeds of $45.0 million for an equipment loan that is secured by certain of our barges and towboats during the nine months ended December 31, 2020.

Long-Term Financing

In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes, common units and/or preferred units, loans from financial institutions, asset securitizations or the sale of assets.

Senior Secured Notes

On February 4, 2021, we issued $2.05 billion of 7.5% 2026 Senior Secured Notes (“2026 Senior Secured Notes”) in a private placement. The 2026 Senior Secured Notes bear interest, which is payable on February 1 and August 1 of each year, which began on August 1, 2021. The 2026 Senior Secured Notes mature on February 1, 2026.

Senior Unsecured Notes

The senior unsecured notes include the 2023 Notes, 6.125% senior unsecured notes due 2025 and 7.5% senior unsecured notes due 2026 (collectively, the “Senior Unsecured Notes”).

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Repurchases

During the three months ended December 31, 2021, we repurchased $20.0 million of the 2023 Notes.

Other Long-term Debt

The Sawtooth credit agreement was paid off and terminated prior to us selling our ownership interest in Sawtooth on June 18, 2021 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

On October 29, 2020, we entered into an equipment loan for $45.0 million which bears interest at a rate of 8.6% and is secured by certain of our barges and towboats. Under this agreement, we are required to make monthly payments of $0.5 million (principal and interest) and a balloon payment of $24.2 million when this loan matures on November 1, 2027.

For additional information related to our long-term debt, see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Capital Expenditures, Acquisitions and Other Investments

The following table summarizes expansion and maintenance capital expenditures (which excludes additions for tank bottoms and linefill and has been prepared on the accrual basis), acquisitions and other investments for the periods indicated.

	Capital Expenditures						Other
	Expansion		Maintenance		Acquisitions (1)		Investments (2)
	(in thousands)
Three Months Ended December 31,
2021	$	13,029	$	13,329	$	—	$	115
2020	$	5,248	$	6,269	$	—	$	31
Nine Months Ended December 31,
2021	$	57,552	$	38,053	$	—	$	350
2020	$	43,606	$	22,267	$	—	$	638

(1)    There were no acquisitions during the three months or nine months ended December 31, 2021 or 2020.

(2)    Amounts for the three months and nine months ended December 31, 2021 and 2020 relate to contributions made to unconsolidated entities.

Capital expenditures for the fiscal year ending March 31, 2022 are expected to be approximately $125 million to $130 million, net of anticipated insurance reimbursements.

Distributions Declared

The board of directors of our general partner decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes. This resulted in the suspension of the quarterly common unit distributions, beginning with the quarter ended December 31, 2020, and all preferred unit distributions, beginning with the quarter ended March 31, 2021. The board of directors of our general partner expects to evaluate the reinstatement of the common unit and all preferred unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, upcoming debt maturities, capital expenditures and the overall performance of our businesses.

Guarantor Summarized Financial Information

NGL Energy Partners LP (parent) and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report). Certain of our wholly owned subsidiaries (“Guarantor Subsidiaries”) have, jointly and severally, fully and unconditionally guaranteed the Senior Unsecured Notes.

The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing

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and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our Senior Unsecured Notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our Senior Unsecured Notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our Senior Unsecured Notes, the release of such Guarantor Subsidiary from its guarantee under our revolving credit facility, the liquidation or dissolution of such Guarantor Subsidiary or upon the consolidation, merger or transfer of all assets of the Guarantor Subsidiary to us or another Guarantor Subsidiary in which the Guarantor Subsidiary dissolves or ceases to exist (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to NGL Energy Partners LP (parent). 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.

The rights of holders of our Senior Unsecured Notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Law, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent Transfer Act or any similar federal or state law.

The following is the summarized financial information for NGL Energy Partners LP (parent) and the Guarantor Subsidiaries on a combined basis after elimination of intercompany transactions, which includes related receivable and payable balances, and the investment in and equity earnings from the non-guarantor subsidiaries. This summarized financial information is provided in accordance with the reporting requirements of Rule 13-01 under Securities and Exchange Commission Regulation S-X.

Balance sheet information:

	NGL Energy Partners LP (Parent) and Guarantor Subsidiaries
	December 31, 2021		March 31, 2021
	(in thousands)
ASSETS:
Current assets	$	1,516,879	$	1,002,708
Noncurrent assets (1)(2)	$	4,544,864	$	4,743,874
LIABILITIES AND EQUITY (3):
Current liabilities	$	1,200,582	$	906,512
Noncurrent liabilities	$	3,595,785	$	3,524,664
Class D Preferred Units	$	551,097	$	551,097

(1)    Excludes $0.2 million and $50.9 million of net intercompany receivables due to NGL Energy Partners LP (parent) and the Guarantor Subsidiaries from the non-guarantor subsidiaries at December 31, 2021 and March 31, 2021, respectively.

(2)    Includes $1.9 billion and $1.9 billion of goodwill and intangible assets at December 31, 2021 and March 31, 2021, respectively.

(3)    There are no noncontrolling interests held at the co-issuers or Guarantor Subsidiaries for either period presented.

Statements of operations information:

	NGL Energy Partners LP (Parent) and Guarantor Subsidiaries
	Nine Months Ended December 31, 2021		Twelve Months Ended March 31, 2021
	(in thousands)
Revenues	$	5,412,442	$	5,214,499
Operating income (loss)	$	41,497	$	(390,210)
Loss from continuing operations	$	(158,353)	$	(636,626)
Net loss (1)	$	(158,353)	$	(638,395)
Loss from continuing operations allocated to common unitholders	$	(236,023)	$	(729,891)

(1)    There are no noncontrolling interests held at the co-issuers or Guarantor Subsidiaries for either period presented.

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Contractual Obligations

For a discussion of contractual obligations, see Note 6, Note 7 and Note 13 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements other than the letters of credit discussed in Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report and the short-term leases discussed in Note 13 to our unaudited 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.

Recent Accounting Pronouncements

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

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of our operations and the use of estimates made by management. We have identified certain accounting policies that are most important to the portrayal of our consolidated financial position and results of operations. The application of these accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, and changes in these accounting policies, could have a material effect on our consolidated financial statements. There have been no material changes in the critical accounting policies previously disclosed in our Annual Report.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

A 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.

The ABL Facility is variable-rate debt with interest rates that are generally indexed to the Wall Street Journal prime rate or LIBOR interest rate (or successor rate). At December 31, 2021, we had $156.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 4.24%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.2 million, based on borrowings outstanding at December 31, 2021.

In addition, on and after certain dates, distributions for our Class B and Class C Preferred Units will be calculated using the applicable three-month LIBOR interest rate (or successor rate) plus a spread. For our Class B Preferred Units, distributions, on and after July 1, 2022, will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or successor rate) plus a spread of 7.213%. For our Class C Preferred Units, distributions, on and after April 15, 2024, will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or successor rate) plus a spread of 7.384%.

Commodity Price Risk

Our operations are subject to certain business risks, including commodity price risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Procedures and limits for managing commodity price risks are

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specified in our market risk policy. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel.

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

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

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. All changes in the fair value of our physical contracts that do not qualify as normal purchases and normal sales and settlements (whether cash transactions or non-cash mark-to-market adjustments) are reported either within revenue (for sales contracts) or cost of sales (for purchase contracts) in our unaudited condensed consolidated statements of operations, regardless of whether the contract is physically or financially settled.

The following table summarizes the hypothetical impact on the December 31, 2021 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)	$	(7,590)
Propane (Liquids Logistics segment)	$	(182)
Butane (Liquids Logistics segment)	$	(2,973)
Refined Products (Liquids Logistics segment)	$	(2,676)
Other Products (Liquids Logistics segment)	$	(16,249)
Canadian dollars (Liquids Logistics segment)	$	80

Changes in commodity prices may also impact the volumes that we are able to transport, dispose, store and market, which also impact our cash flows.

Credit Risk

Our operations are also subject to credit risk, which is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing credit risk are specified in our credit policy. Credit risk is monitored daily and we believe we minimize exposure through the following:

•requiring certain customers to prepay or place deposits for our products and services;

•requiring certain customers to post letters of credit or other forms of surety;

•monitoring individual customer receivables relative to previously-approved credit limits;

•requiring certain customers to take delivery of their contracted volume ratably rather than allow them to take delivery at their discretion;

•entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions;

•reviewing the receivable aging regularly to identify issues or trends that may develop; and

•requiring marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid outstanding invoices.

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At December 31, 2021, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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 December 31, 2021. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2021, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the caption “Legal Contingencies” in Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report, which is incorporated by reference into this Item 1.

Item 1A.    Risk Factors

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2021.

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

During November 2021, 8,901 common units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be “repurchases.” The average price paid per common unit was $2.25. These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 3.    Defaults Upon Senior Securities

Pursuant to certain covenants within the indenture of our 2026 Senior Secured Notes, the board of directors of our general partner temporarily suspended all common unit and preferred unit distributions. For additional information related to the suspension of distributions, see Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

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Item 6.    Exhibits

Exhibit Number	Exhibit
10.1	First Amendment to Credit Agreement (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2021 filed with the SEC on November 9, 2021)
22.1*	List of Issuers and Guarantor Subsidiaries of NGL Energy Partners LP
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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH**	Inline XBRL Schema Document
101.CAL**	Inline XBRL Calculation Linkbase Document
101.DEF**	Inline XBRL Definition Linkbase Document
101.LAB**	Inline XBRL Label Linkbase Document
101.PRE**	Inline XBRL Presentation Linkbase Document
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*    Exhibits filed with this report.

**    The following documents are formatted in Inline XBRL (Extensible Business Reporting Language): (i) Unaudited Condensed Consolidated Balance Sheets at December 31, 2021 and March 31, 2021, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2021 and 2020, (iii) Unaudited Condensed Consolidated Statements of Comprehensive Loss for the three months and nine months ended December 31, 2021 and 2020, (iv) Unaudited Condensed Consolidated Statements of Changes in Equity for the three months and nine months ended December 31, 2021 and 2020, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2021 and 2020, and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

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SIGNATURES

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

	NGL ENERGY PARTNERS LP
	By:	NGL Energy Holdings LLC, its general partner
Date: February 9, 2022		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer
Date: February 9, 2022		By:	/s/ Linda J. Bridges
			Linda J. Bridges
			Chief Financial Officer

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