Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 20192022
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 001-35172
NGL Energy Partners LP
(Exact Name of Registrant as Specified in Its Charter)
Delaware27-3427920
(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification No.)
6120 South Yale Avenue, Suite 805
Tulsa, Oklahoma
74136
Tulsa,Oklahoma74136
(Address of Principal Executive Offices)(Zip Code)
(918)(918) 481-1119
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading SymbolsName of Each Exchange on Which Registered
Common units representing Limited Partner InterestsNGLNew York Stock Exchange
Fixed-to-floating rate cumulative redeemable perpetual preferred unitsNGL-PBNew York Stock Exchange
Fixed-to-floating rate cumulative redeemable perpetual preferred unitsNGL-PCNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:   None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes x   No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes o   No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes x   No o
Indicate by check mark whether the registrant has submitted electronically 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 x   No o
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 fileroAccelerated filerx
Non-accelerated fileroSmaller reporting company
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth companyo
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.   
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes o   No x
The aggregate market value at September 30, 20182021 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of the Common Units on the New York Stock Exchange on such date ($11.602.37 per Common Unit) was $1.0 billion.$243.4 million. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.
At May 28, 2019,June 1, 2022, there were 125,966,868130,695,970 common units issued and outstanding.




TABLE OF CONTENTS



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Forward-Looking Statements

This Annual Report on Form 10-K (“Annual 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 Annual Report such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key risk factors that may affect our consolidated financial position and results of operations are:

the prices of crude oil, natural gas liquids, gasoline, diesel, ethanol,biodiesel and biodiesel;
energy prices generally;
the general level of crude oil, natural gas, and natural gas liquids production;
the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, diesel ethanol, and biodiesel;
the level of crude oil and natural gas drilling and production in areas where we have water treatmentoperations and disposal facilities;
the price of gasoline relative to the price of corn, which affects the price of ethanol;
the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas;
actions taken by foreign oil and gas producing nations;
the political and economic stability of foreign oil and gas producing nations;
the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;
the effect of natural disasters, earthquakes, hurricanes, tornados, lightning strikes, or other significant weather events;
the availability of local, intrastate, and interstate transportation infrastructure with respect to our truck, railcar, and barge transportation services;
the availability, price, and marketing of competing fuels;
the effect of energy conservation efforts on product demand;
energy efficiencies and technological trends;
governmental regulation and taxation;
the effectissuance of legislative and regulatory actions on hydraulic fracturing, wastewater disposal, and the treatment of flowback and produced water;
hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;
the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;
loss of key personnel;
the ability to renew contracts with key customers;
the ability to maintain or increase the margins we realize for our terminal, barging, trucking, wastewater disposal, recycling, and discharge services;
the ability to renew leases for our leased equipment and storage facilities;
the nonpayment or nonperformance by our counterparties;
the availability and cost of capital and our ability to access certain capital sources;

a deterioration of the credit and capital markets;
the ability to successfully identify and complete accretive acquisitions, and integrate acquired assets and businesses;
changes in the volume of hydrocarbons recovered during the wastewater treatment process;
changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;
executive orders, changes in applicable laws, regulations and regulations,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 regulationspolicies (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;
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;
any reduction or the elimination of the federal Renewable Fuel Standard;
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changes in general economic conditions, including market and macroeconomic disruptions resulting from pandemics, including the jurisdictional characteristicscurrent COVID-19 pandemic, and related governmental responses;
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 the applicable regulatory policies with respect to, our pipeline assets;biodiesel; and
other risks and uncertainties, including those discussed under Part I, Item 1A–“Risk Factors.”

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Annual 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.”


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PART I

References in this Annual Report to (i) “NGL Energy Partners LP,” the “Partnership,” “we,” “our,” “us,” or similar terms refer to NGL Energy Partners LP and its operating subsidiaries, (ii) “NGL Energy Holdings LLC” or “general partner” refers to NGL Energy Holdings LLC, our general partner, (iii) “NGL Energy Operating LLC” refers to NGL Energy Operating LLC, the direct operating subsidiary of NGL Energy Partners LP, and (iv) the “NGL Energy GP Investor Group” refers to, collectively, the 4445 individuals and entities that own all of the outstanding membership interests in our general partner, and (v) the “NGL Energy LP Investor Group” refers to, collectively, the 15 individuals and entities that owned all of our outstanding common units before the closing date of our initial public offering.partner.

We have presented operational data in Part I, Item 1–“Business” for the year ended March 31, 2019.2022. Unless otherwise indicated, this data is as of March 31, 2019.2022.

Item 1.    Business

Overview

We are a Delaware limiteddiversified midstream energy partnership that transports, treats, recycles and disposes of produced water generated as part of the energy production process as well as transports, stores, markets and provides other logistics services for crude oil and liquid hydrocarbons. Originally formed in September 2010. At March 31, 2019,2010, we are a Delaware master limited partnership and our operations included:business is currently organized into the following three segments:

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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 trucking, marine and pipeline 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 owned and leased pipelines.
Our Water SolutionsLiquids Logistics segment providesconducts 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 owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and expect to commence operations on our propane pipeline in Michigan in June 2022.

Business Repositioning

Over the treatmentpast several years, we have undertaken a number of important strategic actions in an effort to leverage the Partnership’s core areas of competitive strength and focus on generating stable, growing and predictable cash flows, while improving our credit profile. These steps included the sale of the following:

Our Retail Propane segment during the years ended March 31, 2018 and 2019;
Certain non-core water disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms, drilling fluids and drilling muds and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services and sells freshwater to producers for exploration and production activities.
Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 27 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility joint venture in Utah.
Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarilybusinesses in the Gulf Coast, SoutheastPermian and MidwestBakken Basins during the year ended March 31, 2019;
Certain refined products businesses including 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 and schedules them for delivery at various locations throughout(“Gas Blending”) during the country. In addition, in certain storage locations, our Refined Productsyear ended March 31, 2020; and Renewables segment may also purchase unfinished gasoline blending components for subsequent blending into finished gasoline to supply our marketing business as well as third parties.

OnOur interest in Sawtooth Caverns, LLC (“Sawtooth”) during the year ended March 30, 2018,31, 2022.

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In our Water Solutions segment we sold a portionacquired strategic water infrastructure assets including Mesquite Disposals Unlimited, LLC (“Mesquite”) and the equity interests of Hillstone Environmental Partners, LLC (“Hillstone”) during the year ended March 31, 2020, while in our Liquids Logistics segment, we acquired DCP Midstream LP’s natural gas liquids business during the year ended March 31, 2019 and an approximately 225-mile propane pipeline in Michigan (the “Ambassador Pipeline”) during the year ended March 31, 2021.

The sales of our Retail Propane segment and TPSL, Mid-Con and Gas Blending have allowed us to DCC LPG (“DCC”). On July 10, 2018,reduce working capital indebtedness and decrease earnings volatility. The purchase of the two strategic water infrastructure assets assists in furthering our ongoing strategy of cash flow predictability by adding long-term contracts under acreage dedications and minimum volume commitments and provides us with significant scale and capabilities that will facilitate high-quality execution for our customers. The purchase of the natural gas liquids terminals and the Ambassador Pipeline complement our existing natural gas liquids portfolio, provides strategic access to water for international import and export activity and also creates additional opportunities for new and existing customers to supply their business.

We believe these collective actions have substantially simplified our business mix and has allowed us to focus on what we completedbelieve are the sale of virtually allcore areas of our remaining Retail Propane segment to Superior Plus Corp. (“Superior”)business and on August 14, 2018, we soldimproved our previously held interest in Victory Propane, LLC (“Victory Propane”).overall financial position. These transactions represent a strategic shiftare expected to position us for sustained growth in the future.

For more information regarding our operations and will have a significant effect on our operations and financial results going forward. Accordingly, the results of operations and cash flows related to our former Retail Propane segment (including equity in earningsreportable segments, see Part II, Item 7–“Management’s Discussion and Analysis of Victory Propane) have been classified as discontinued operations for all periods presentedFinancial Condition and prior periods have been retrospectively adjusted in the consolidated statementsResults of operationsOperations” and consolidated statements of cash flows. In addition, the assets and liabilities related to our former Retail Propane segment have been classified as held for sale within our March 31, 2018 consolidated balance sheet. See Note 1711 to our consolidated financial statements included in this Annual Report for a further discussion of the transaction.

Report. For more information regarding our reportable segments,dispositions and acquisitions transactions and the impact to our operations, see Note 17 and Note 18 to our consolidated financial statements included in this current Annual Report and ourAnnual Report on Form 10-K for the years ended March 31, 2021 and 2020.

Debt Refinancing

As previously disclosed, on February 4, 2021, we closed on a private offering of $2.05 billion of 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) and a new credit agreement which consisted of a $500.0 million asset-based revolving credit facility (“ABL Facility”). We used the net proceeds from the issuance to repay all outstanding borrowings under and terminate our former revolving credit facility and our term credit agreement, as well as to pay fees and expenses. As part of this refinancing, we also agreed to certain restricted payment provisions under the 2026 Senior Secured Notes and ABL Facility, one of which was the suspension of the quarterly common unit distributions, which began with the quarter ended December 31, 2020, and all preferred unit distributions, which began with the quarter ended March 31, 2021.

On April 13, 2022, we amended the ABL Facility to increase the commitments to $600.0 million under the accordion feature within the ABL Facility. As part of the amendment, we agreed to reduce the commitments back to $500.0 million on or before March 31, 2023.

For additional information related to the ABL Facility and 2026 Senior Secured Notes, see Note 127 to our consolidated financial statements included in this Annual Report.



Acquisitions

The following summarizes our acquisitions over the past five fiscal years.

Year Ended March 31, 2015

In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). The operations of TransMontaigne included the marketing of refined products. As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne, the 2% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TransMontaigne Partners L.P. (“TLP”), and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne. See “Dispositions” below for a discussion of the sale of the general and limited partner interests in TLP.
In November 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota. See “Dispositions” below for a discussion of the sale of our Bakken saltwater disposal business.
In February 2015, we acquired Sawtooth Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. See “Dispositions” below for a discussion of the joint venture of our Sawtooth business.
During the year ended March 31, 2015, we acquired 16 water treatment and disposal facilities under a previous development agreement.
During the year ended March 31, 2015, we acquired eight retail propane businesses. See “Dispositions” below for a discussion of the sale of our Retail Propane segment.

Year Ended March 31, 2016

In August 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin portion of the Permian Basin in West Texas. See “Dispositions” below for a discussion of the sale of our South Pecos water disposal business.
In January 2016, we acquired a 57.125% interest in NGL Water Pipelines, LLC operating in the Delaware Basin portion of the Permian Basin in West Texas.
During the year ended March 31, 2016, we acquired 15 water treatment and disposal facilities under a previous development agreement.
During the year ended March 31, 2016, we acquired six retail propane businesses. See “Dispositions” below for a discussion of the sale of our Retail Propane segment.

Year Ended March 31, 2017

In June 2016, we acquired an additional 24.5% interest in NGL Water Pipelines, LLC operating in the Delaware Basin portion of the Permian Basin in West Texas.
In June 2016, we acquired the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”). See “Dispositions” below for a discussion of the sale of Grassland.
In September 2016, we acquired the remaining 25% ownership interest in three water solutions facilities in the Eagle Ford shale play in Texas.
In January 2017, we acquired a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a natural gas liquids and condensate facility in Kingfisher, Oklahoma.
During the year ended March 31, 2017, we acquired three water treatment and disposal facilities.
During the year ended March 31, 2017, we acquired four retail propane businesses. See “Dispositions” below for a discussion of the sale of our Retail Propane segment.

Year Ended March 31, 2018

During the year ended March 31, 2018, we acquired the remaining 50% ownership interest in NGL Solids Solutions, LLC.

During the year ended March 31, 2018, we acquired seven retail propane businesses and certain assets from Victory Propane. See “Dispositions” below for a discussion of the sale of our Retail Propane segment.

Year Ended March 31, 2019

On April 24, 2018, we acquired the remaining 18.375% interest in NGL Water Pipelines, LLC operating in the Delaware Basin portion of the Permian Basin in West Texas.
During the three months ended June 30, 2018, we acquired three retail propane businesses. See “Dispositions” below for a discussion of the sale of our Retail Propane segment.
In January 2019, we acquired two refined products terminals located in Georgia.
In March 2019, we acquired a natural gas liquids terminal business that consisted of five propane rail terminals, located in the Eastern United States, a 50% ownership interest in an additional rail terminal, located in the state of Maine, and an import/export terminal located in Chesapeake, Virginia, with the capability to load and unload ships ranging in size from handy-sized vessels up to very large gas carriers.
During the year ended March 31, 2019, we acquired six saltwater disposal facilities (including 22 saltwater disposal wells), two ranches and four freshwater facilities (including 45 freshwater wells).

Year Ending March 31, 2020

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See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of the acquisitions that occurred subsequent to March 31, 2019.

Dispositions

Year Ended March 31, 2016

Sale of General Partner Interest in TLP

On February 1, 2016, we sold our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for net proceeds of $343.1 million. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. As discussed further below, TLP is no longer an equity method investment. As part of this transaction, we retained TransMontaigne Product Services LLC, including its marketing business, customer contracts and its line space on the Colonial and Plantation pipelines, which is a significant part of our Refined Products and Renewables segment. We also entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. See Note 15 to our consolidated financial statements included in this Annual Report for a further discussion.

Year Ended March 31, 2017

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

Sale of Grassland

On November 29, 2016, we sold Grassland and received proceeds of $22.0 million. See Note 13 to our consolidated financial statements included in this Annual Report for a further discussion.

Year Ended March 31, 2018

Sale of Interest in Glass Mountain Pipeline, LLC (“Glass Mountain”)

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain for net proceeds of $292.1 million. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.


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 Crude Oil Logistics segment have not been classified as discontinued operations.

Sawtooth Joint Venture

On March 30, 2018, we completed the transaction to form a joint venture with Magnum Liquids, LLC, a portfolio company of Haddington Ventures LLC, along with Magnum Development, LLC and other Haddington-sponsored investment entities (collectively “Magnum”) to focus on the storage of natural gas liquids and refined products by combining our Sawtooth salt dome storage facility with Magnum’s refined products rights and adjacent leasehold.Magnum acquired an approximately 28.5% interest in Sawtooth from us, in exchange for consideration consisting of a cash payment of approximately $37.6 million (excluding working capital) and the contribution of certain refined products rights and adjacent leasehold. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

Sale of a Portion of Retail Propane Business

On March 30, 2018, we sold a portion of our Retail Propane segment to DCC for net proceeds of $212.4 million in cash. The Retail Propane businesses subject to this transaction consisted of our operations across the Mid-Continent and Western portions of the United States. We retained our Retail Propane businesses located in the Eastern, mid-Atlantic and Southeastern sections of the United States. See Note 17 to our consolidated financial statements included in this Annual Report for a further discussion.

Year Ended March 31, 2019

Sale of Interest in E Energy Adams, LLC

On May 3, 2018, we sold our previously held 20% interest in E Energy Adams, LLC for net proceeds of $18.6 million. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Sale of Remaining Retail Propane Business

On July 10, 2018, we completed the sale of virtually all of our remaining Retail Propane segment to Superior for total consideration of $889.8 million in cash. On August 14, 2018, we sold our previously held interest in Victory Propane. See Note 17 to our consolidated financial statements included in this Annual Report for a further discussion.

Sale of Bakken Saltwater Disposal Business

On November 30, 2018, we completed the sale of NGL Water Solutions Bakken, LLC to an affiliate of Tallgrass Energy, LP for $85.0 million in net cash proceeds and recorded a gain on disposal of $33.4 million during the year ended March 31, 2019. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

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 Water Solutions segment have not been classified as discontinued operations.

Sale of South Pecos Water Disposal Business

On February 28, 2019, we completed the sale of our South Pecos water disposal business to a subsidiary of WaterBridge Resources LLC for $232.2 million in net cash proceeds and recorded a gain on disposal of $107.9 million during the year ended March 31, 2019. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

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 Water Solutions segment have not been classified as discontinued operations.



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Table of Contents

Primary Service Areas

The following map shows the primary service areas of our businesses at March 31, 2019:nglmap5719.jpg2022:

ngl-20220331_g1.jpg
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Organizational Chart

The following chart provides a summarized viewoverview of our legal entity structure at March 31, 2019:2022:


ngl-20220331_g2.jpg


(1)Includes (i) NGL Crude Logistics, LLC, which includes the operations of our Crude Oil Logistics business and a portion of our Refined Products and Renewables businesses, (ii) NGL Water Solutions, LLC, which includes the operations of our Water Solutions business, (iii) NGL Liquids, LLC, which includes the operations of our Liquids business, and (iv) TransMontaigne, LLC, which includes the remaining portion of our Refined Products and Renewables businesses.

(1)    Includes (i) NGL Water Solutions, LLC, which includes the operations of our Water Solutions segment, (ii) NGL Crude Logistics, LLC, which includes the operations of our Crude Oil Logistics segment and certain of our businesses within our Liquids Logistics segment and (iii) NGL Liquids, LLC, which includes the operations of certain of our businesses within our Liquids Logistics segment.


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Our Business Strategies

Our principal business objectives are to maximize the profitability and stability of our businesses, grow our businesses in an accretive and prudent manner, and maintain a strong balance sheet. We intend to accomplish these business objectives by executing the following strategies:

Focus on building a vertically integrated midstream master limited partnership providing multiple services to customers. We continue to enhance our ability to transport crude oil from the wellhead to refiners, refined products from refiners to customers, wastewater from the wellhead to treatment for disposal, recycle, or discharge, and natural gas liquids from processing plants to end users.
Achieve organic growth by investing in new assets that increase volumes, enhance our operations, and generate attractive rates of return. We believe that there are accretive organic growth opportunities that originate from assets we own and operate. We have invested and expect to continue to invest within our existing businesses, particularly within our Crude Oil Logistics and Water Solutions businesses as we grow these businesses with highly accretive, fee-based organic growth opportunities.
Deliver accretive growth through strategic acquisitions that complement our existing business model and expand our operations. We intend to continue to pursue acquisitions that build upon our vertically integrated business model, add scale to our current operating platforms, and enhance our geographic diversity in our businesses. We have established a successful track record of acquiring companies and assets at attractive prices and we continue to evaluate acquisition opportunities in order to capitalize on this strategy in the future.
Focus on consistent annual cash flows by adding operations that minimize commodity price risk and generate fee-based, cost-plus, or margin-based revenues under multi-year contracts. We intend to focus on long-term fee-based contracts in addition to back-to-back contracts which minimize commodity price exposure. We continue to increase cash flows that are supported by certain fee-based, multi-year contracts, some of which include acreage dedications from producers or volume commitments.
Maintain a disciplined cash distribution policy that complements our leverage, acquisition and organic growth strategies. We target leverage levels that are consistent with those of investment grade companies. During the year ended March 31, 2019, we reduced our outstanding indebtedness by $528.2 million, including current maturities. We will seek to maintain sufficient liquidity and credit metrics to manage existing and future capital requirements and to take advantage of market opportunities, and expect to continue to evaluate the capital markets and may opportunistically pursue financing transactions to optimize our capital structure.

Prudently manage our balance sheet to provide us with maximum financial flexibility for funding our operations, capital projects and strategic acquisitions. Our primary focus is to reduce our absolute debt and leverage and maintain sufficient liquidity to reduce our overall leverage below 4.75 to 1.00 and reinstate the payment of distributions. We are also focused on maintaining credit metrics to manage existing and future capital requirements as well as to take advantage of market opportunities. We expect to continue to evaluate the capital markets and may opportunistically pursue financing transactions to optimize our capital structure.
Focus on building a diversified midstream master limited partnership providing multiple services to customers. We continue to enhance our ability to transport produced water from the wellhead to treatment for disposal, recycle, or discharge, crude oil from the wellhead to refineries, and natural gas liquids from processing plants and supply hubs to end users.
Operate in a safe and environmentally responsible manner. We seek to operate our business in a safe and environmentally responsible manner by working with our employees, customers, vendors and local communities to minimize our environmental impact and comply with local, state and federal environmental laws and regulations.
Focus on consistent annual cash flows from operations under multi-year contracts that minimize commodity price risk and generate fee-based revenues. We intend to focus on generating revenues under long-term fixed fee contracts in addition to back-to-back contracts which minimize direct commodity price exposure. We seek to continue to increase cash flows that are supported by certain fixed fee, multi-year contracts, some of which include acreage dedications from producers or minimum volume commitments.
Achieve growth by utilizing our existing footprint of assets, investing in new assets, customers and ventures that increase volume and enhance our operations, and generate attractive rates of return. We have available capacity in many of the assets that we own and operate that can be utilized to increase cash flows with minimal incremental capital investment. We have invested and expect to continue to invest within our existing businesses to capitalize on accretive, organic growth opportunities. We also continue to pursue strategic transactions and ventures that complement and enhance our existing footprint.

Our Competitive Strengths

We believe that we are well positioned to successfully execute our business strategies and achieve our principal business objectives because of the following competitive strengths:

Our vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-year basis. Our ability to provide multiple services to customers in numerous geographic areas enhances our competitive position. Our four business units are diversified by geography, customer-base and commodity sensitivities which we believe provides us with the ability to maintain cash flows throughout typical commodity cycles. We believe that our Liquids business provides us with valuable market intelligence that helps us identify potential acquisition opportunities. Our Refined Products business benefits from lower energy prices driving increased customer demand, which can offset the downward pressure on our Crude Oil Logistics and Water Solutions businesses in a low price environment.
Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales. Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to the optimal markets.
Our water processing facilities, which are strategically located near areas of high crude oil and natural gas production. Our water processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Permian Basin, the DJ Basin, the Eagle Ford shale play and the Pinedale Anticline. In addition, we believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations.

Our network of natural gas liquids transportation, terminal, and storage assets, which allows us to provide multiple services over the continental United States. Our strategically located terminals, large railcar fleet, shipper status on common carrier pipelines, and substantial leased and owned underground storage enable us to be a preferred purchaser and seller of natural gas liquids.
Our access to refined products pipeline and terminal infrastructure. Our capacity allocations on third-party pipelines and our proprietary access to refined products terminals give us the opportunity to serve customers over a large geographic area.
Our seasoned management team with extensive midstream industry experience and a track record of acquiring, integrating, operating and growing successful businesses. Our management team has significant experience managing companies in the energy industry, including master limited partnerships. In addition, through decades of experience, our management team has developed strong business relationships with key industry participants throughout the United States. We believe that our management’s knowledge of the industry, relationships within the industry, and experience in identifying, evaluating and completing acquisitions provides us with opportunities to grow through strategic and accretive acquisitions that complement or expand our existing operations.

Our water processing facilities, which are strategically located near areas of high crude oil and natural gas production. Our water processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Delaware Basin, the Midland Basin, the Denver-Julesburg (“DJ”) Basin and the Eagle Ford Basin. These assets are underpinned by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments. Additionally, we believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations as needed. Our system located in the Northern Delaware Basin is an integrated network of large diameter produced water pipelines, recycling facilities and disposal wells that collectively provides reliable service to producer customers and would be difficult for competitors to replicate at this time.

Our network of crude oil transportation and storage assets, which allows us to serve customers over a wide geographic area and optimize sales. Our strategically deployed terminals, towboats and barges, as well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to optimal markets. These operations are supported by certain long-term, fixed rate contracts with producers, refiners and marketers and include minimum volume commitments on our owned and leased pipelines.
Our network of natural gas liquids transportation, terminal, and storage assets, which allows us to provide multiple services across the United States and Canada. Our strategically located terminals, large leased railcar fleet, shipper status on common carrier pipelines, and substantial leased storage enable us to be a preferred
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purchaser and seller of natural gas liquids. We have a diverse base of long-standing customers and believe that our performance metrics allow us to reliably supply, store and transport products throughout the United States and Canada.
Our diversified operations allow us to generate more predictable and stable cash flows on a year-to-year basis. Our ability to provide multiple services to customers in numerous geographic areas enhances our competitive position. Our three business segments are diversified by geography, customer base and commodity sensitivities, which we believe provides us with more stable cash flows through the typical commodity cycles.
Our seasoned management team with extensive midstream industry experience and a track record of acquiring, integrating, operating and growing successful businesses. Our management team has significant experience managing companies in the energy industry, including master limited partnerships. In addition, through decades of experience, our management team has developed strong business relationships with key industry participants throughout the United States. We believe that our management’s knowledge of the industry, relationships within the industry, and experience provide us with the opportunities to optimize our existing assets. Our management team also has experience in identifying, evaluating and completing acquisitions and other ventures that provide us with additional opportunities to complement, grow and expand our existing operations.

Our Businesses

Water Solutions

Overview. Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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.

We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the Midland Basin in Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 656.2 million barrels of produced water across its areas of operation during the year ended March 31, 2022, we believe that we are the largest independent produced water transportation and disposal company in the United States. We currently have over 660,000 acres dedicated to our system under long-term agreements in the Northern Delaware Basin. In addition, we have several minimum volume commitments and other commercial agreements covering the Delaware, Midland, Eagle Ford, DJ and Pinedale Anticline Basins. Our focus in building our Water Solutions business has been to secure long-term, fixed fee contracts that contain minimum volume commitments, acreage dedications or similarly strong contractual relationships with large, well-capitalized producer customers.

Our core asset in the Water Solutions segment is our system located in the Northern Delaware Basin, where we own and operate the largest integrated network of large diameter produced water pipelines, recycling facilities and disposal wells. This system spans six counties in New Mexico and Texas that represent one of the most prolific crude oil producing regions in the United States with some of the most economic hydrocarbon resources and lowest break-even economics for producers. Our system has approximately 650 miles of newly-built, in-service large diameter produced water pipelines connected to 58 active saltwater disposal facilities and 122 active disposal wells. We have over 660,000 acres dedicated to the Northern Delaware system providing a multi-decade drilling inventory and significant growth opportunity.

We own or have a possessory interest in over 120,000 acres of real estate on two ranches located in Eddy and Lea Counties, New Mexico. Our two ranches include 16 commercial water permits and four strategically located brackish non-potable water facilities (including 45 brackish non-potable water wells). Additionally, on both ranches we are organically developing surface mineral mining operations, solid waste facilities, and are exploring other uses for our real estate holdings.

In February 2022, our Water Solutions segment announced a collaboration with XRI Holdings, LLC (“XRI”) to advance full cycle produced water management across operations in the Northern Delaware Basin. This collaboration will benefit from each of our unique characteristics by leveraging existing infrastructure assets, technology, and experience, as we own and operate the largest integrated produced water pipeline system in the Northern Delaware Basin and XRI is the largest produced water recycling company in the Permian Basin, allowing us the opportunity to address the greatly increasing demand for sustainable use of produced water in our customers’ completions activities. The flexible, non-exclusive nature of this joint effort allows each of us to continue to operate produced water reuse and recycling activities independent of one another. During
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the year ended March 31, 2022, we sold approximately 34.1 million barrels of recycled water, which includes the sale of produced water and recycled water for use in our customers’ completion activities.

Operations. We own 111 water treatment and disposal facilities, including 212 injection wells. The location and permitted processing capacities of these facilities are summarized below.
Number ofNumber ofPermitted Processing Capacity (barrels per day)
LocationFacilitiesWellsOwn (1)Lease (2)Total
Permian Basin
Delaware Basin (3) - Texas and New Mexico58 122 1,514,000 3,297,300 4,811,300 
Midland Basin (3) - Texas14 14 358,300 — 358,300 
Eagle Ford Basin (3)(4) - Texas22 36 549,000 362,000 911,000 
DJ Basin - Colorado13 32 393,000 162,500 555,500 
Granite Wash (3) - Texas60,000 — 60,000 
Pinedale Anticline Basin (5) - Wyoming— 90,240 90,240 
Eaglebine - Texas20,000 — 20,000 
Total - All Facilities111 212 2,894,300 3,912,040 6,806,340 
(1)    These facilities are located on lands we own.
(2)    These facilities are located on lands we lease.
(3)    Certain facilities can dispose of both produced water and solids such as tank bottoms, drilling fluids and drilling muds.
(4)    Includes one facility with a permitted processing capacity of 40,000 barrels per day in which we own a 75% interest.
(5)    This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard.

Our customers bring produced and flowback water generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline gathering systems and by truck. During the year ended March 31, 2022, in the Delaware Basin we received approximately 98% of produced and flowback water via pipelines. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.

Our facilities in Colorado, New Mexico and Texas dispose of produced water primarily into deep underground formations via injection wells. At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells.

Our facility servicing the Pinedale Anticline Basin in Wyoming has the assets and technology needed to treat the water more extensively than a typical disposal facility. At this facility, we have the option of disposing of the water in underground injection wells or recycling the water. With regard to recycling the water, we either process the water to the point where it can be returned to producers to be reused in future drilling operations (recycle quality water), which minimizes the impact on the aquifer, or we can treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem (discharge quality water).

Customers. The primary customers of our operations consist mainly of large publicly traded, oil and gas companies with diversified acreage positions across multiple leading oil and gas plays. During the year ended March 31, 2022, 69% of the revenues of our Water Solutions segment were generated from our ten largest customers of the segment.

Competition. The principal elements of competition are system reliability, project execution capability and reputation, system capacity and flexibility, rates for services and system location relative to the producer’s operations. Our competitors include independent produced water transportation and disposal companies and the water transportation and disposal operations owned by oil and gas production companies themselves. Location can be an important consideration for our customers, who seek to minimize the cost of transporting the produced water to disposal facilities. Many of our facilities are strategically located near areas of high crude oil and natural gas production which provides us with a distinct advantage over a competitor that must build a system that can compete with our assets.

Pricing Policy. We charge customers a fee per barrel of produced water received. Our contractual agreements can consist of: (a) minimum volume commitments requiring the customer to deliver a specified minimum volume of produced water over a specified period of time; (b) acreage dedications requiring the customer to deliver all volumes produced from the dedicated acreage with us; and (c) produced water pipeline and trucked disposal agreements providing interruptible service in exchange for a fee per barrel of produced water received. We also generate revenue from the sale of crude oil we recover in
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processing the produced water. In addition, we may charge fees for the sale of produced water for reuse by our customers, pipeline transportation fees, pipeline interconnection fees and solids disposal fees.

Trade Names. Our Water Solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names.

Technology. We hold multiple patents for processing technologies. We believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations.

Crude Oil Logistics

Overview. 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 trucking, marine and pipeline 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 owned and leased pipelines. Our operations are centered near areas of highconcentrated in and around four prolific crude oil production, such asproducing regions in the Bakken shale play in North Dakota,United States - the DJ Basin in Colorado, the Permian Basin in Texas and New Mexico, the Eagle Ford shale playBasin in Texas and the Anadarko Basin, including the STACK, SCOOP, Granite Wash and Mississippi Lime plays in Oklahoma and Texas, and southern Louisiana at theUnited States Gulf of Mexico.Coast.

We ownOur foundational asset in this segment is the Grand Mesa Pipeline (“Grand Mesa”), a 550-mile pipeline that transports crude oil from its origin in Weld County, Colorado to our terminal in Cushing, Oklahoma (the “Grand Mesa Pipeline”).Oklahoma. Grand Mesa Pipeline commenced operations on November 1, 2016 and thehas operated continuously since then. The main line portion of this pipepipeline is comprised of a 37.5%an undivided interest in a crude oil pipeline jointly owned with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) wherein which we have the right to utilizeuse 150,000 barrels per day of capacity.capacity of the pipeline. During the year ended March 31, 2019, there2022, approximately 28.4 million barrels (volume amounts are from both internal and external parties) of crude oil were approximately 117,000 barrels per day transported on the Grand Mesa Pipeline. Operating costs associated with Grand Mesa are allocated to us based on our proportionate ownership interest and throughput. We also own 970,000and operate origin terminals at Lucerne and Riverside, Colorado, where we aggregate crude volumes of different types and grades and store them until they are ready for transfer to our Grand Mesa Pipeline. The Lucerne terminal has 950,000 barrels of operational tankage related to the Grand Mesa Pipeline.and a 12 bay truck loading facility. The Riverside terminal has 20,000 barrels of storage and a four bay truck loading facility.

Through our undivided interest in the Grand Mesa Pipeline, we have sufficient capacity sufficient to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We retained ownership of our previously-acquiredpreviously acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements, to the extent such easements remain in effect, for projects involving the transportation of crude oil and condensate.

We own and operate a large scale crude oil terminal located in Cushing, Oklahoma with 3,626,000 barrels of storage capacity, seven off-loading lease automatic custody transfer units (“LACTs”), a full control room, on-site laboratory, and three 24-inch bi-directional pipelines each capable of moving 360,000 barrels per day. The terminal features advantaged connectivity to other terminals and pipelines including important connections to our Grand Mesa Pipeline and to TC Energy’s terminal with access to the United States Gulf Coast via Marketlink. Our terminal is situated on 200 acres and is designed to be expanded based on customer demand. Cushing is one of the most liquid crude oil trading hubs in the world and is the delivery point for the West Texas Intermediate futures contracts.

We own and operate a crude oil marine terminal in Point Comfort, Texas with 355,000 barrels of storage capacity, six off-loading LACTs and three docks (two for ocean-going barges and ships and one for inland barges).

We own and operate a crude oil pipeline and marine terminal in Houma, Louisiana with 288,000 barrels of storage capacity, two off-loading LACTs, a brown water barge dock and two 12-inch bi-directional pipelines each capable of moving 120,000 barrels per day with connectivity to Shell’s Zydeco System.

Operations. We purchase crude oil from producers and marketers and transport it to refineries or for resale. Our strategically deployed railcar fleet,terminals, towboats and barges, and trucks, andas well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to the optimal markets.

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We currently transport crude oil using the following assets:

170The Grand Mesa Pipeline, which is described above, and 20 other common carrier pipelines owned trucksby third parties;
396 owned and 248 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountain regions;
397 owned210 leased railcars (all of which are leased to third parties) and 246 leased railcars (all of which areor subleased to third parties) operating primarily in Arizona, California, Colorado, Florida, Louisiana, New Mexico, Oklahoma, Oregon, Texas,; and Washington as well as Mexico; and
1013 owned towboats and 1924 owned barges operating primarily in the intercoastal waterways of the United States Gulf Coast and along the Mississippi and Arkansas riverRiver systems. We purchased an additional barge in April 2022.


OfAll of our 397396 owned railcars all are crude oil compliant with the standards for railcars built subsequent to 2011. Of our 246and 210 leased railcars 210 are crude oil compliant with the standards for railcars built subsequent to 2011 (seefor the commodities they are transporting. (See Part I, Item 1A–“Risk Factors”1 “Government Regulation”).

We contract for truck, rail, and barge transportation services from third parties and ship on 20 common carrier pipelines. Wealso own 27 strategically located pipeline injection stations, the locations of which are summarized below.
StateNumber of Pipeline Injection Stations
Texas1413 
OklahomaNew Mexico6
New MexicoOklahoma5
Kansas2
Total27

We also have commitments on several interstate pipelines for transportation of crude oil.

We own six storage terminal facilities. The largest of these is a terminal in Cushing, Oklahoma with a storage capacity of 3,626,602 barrels. The combined storage capacity of the other five terminals is 1,605,242 barrels.

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain. Glass Mountain is a 210-mile crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day.

Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2019, 79%2022, 90% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment. In additionsegment, of which CITGO Petroleum Corporation accounted for 12.8% of our consolidated revenues for the year ended March 31, 2022. Sales to utilizingthis customer occur mainly out of our assets to transport crude oil we own, we also provide truck transportation, barge transportation, storage,terminal in Cushing, Oklahoma.

Additionally, certain key customers of the Crude Oil Logistics segment contribute significantly to the cash flows and terminal throughput services toprofitability of the organization. Any loss of those customers or their contracts could have an adverse impact on our customers.financial results.

Competition. Our Crude Oil Logistics businesssegment faces significant competition, as many entities are engaged in the crude oil logistics business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

price;
availability of supply;supply and refinery demand;
reliability of service;
open credit;
logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars trucks, and towboats; and
long-term customer relationships; andrelationships.
the acquisition of businesses.

Supply. We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil from approximately 200350 producers at approximately 2,3005,700 leases.

Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma.Oklahoma, St. James, Louisiana, and Magellan East Houston. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by hedging exposure due to fluctuations in actual volumes and scheduled volumes.

Our profitability is impacted by forward crude oil prices. Crude oil markets can either be in contango (a condition in which forward crude oil prices are greater than spot prices) or can be in backwardation (a condition in which forward crude oil prices are lower than spot prices). Our Crude Oil Logistics businesssegment benefits when the market is in contango, as increasing prices result in inventory holdingvalue gains during the time between when we purchase the inventory and when we sell it. In addition, we are able to better utilize our storage assets when contango markets justify storing barrels. When markets are in
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backwardation, fallingour inventory values decrease during the time period between when we purchase inventory and when we sell it and the declining prices also typically have an unfavorable impact on our margins.


storage tank lease rates. To help mitigate the impact of changing prices, we enter into derivative instruments to hedge our inventory.
Billing and Collection Procedures.
Our Crude Oil Logistics customers consist primarily of crude oil refiners, producers, and marketers. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on these customers. We believe the following procedures enhance our collection efforts with these customers:

we require certain customers to prepay or place deposits for our products and services;
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables; 
we review receivable aging analyses regularly to identify issues or trends that may develop; and
we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

Trade Names. Our Crude Oil Logistics segment operates primarily under the NGL Crude Logistics, NGL Crude Transportation, NGL Marine, NGL Crude Terminals and NGL MarineCrude Cushing trade names.

Water Solutions

Liquids Logistics
Overview.
Overview. Our Water SolutionsLiquids Logistics segment providesconducts 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 owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars. We also provide services for the treatmentmarine exports of butane through our facility located in Chesapeake, Virginia, and disposalexpect to commence operations on our propane pipeline in Michigan in June 2022. We employ a number of wastewater generated from crude oilcontractual and natural gas productionhedging strategies to minimize commodity exposure and for the disposalmaximize earnings stability of solids such as tank bottoms, drilling fluids and drilling muds and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services and sells freshwater to producers for exploration and production activities. Our water processing facilities are strategically located near areas of high crude oil and natural gas production, including the Midland Basin in Texas and Delaware Basin in Texas and New Mexico, the DJ Basin in Colorado, the Eagle Ford shale play in Texas, and the Pinedale Anticline in Wyoming.this segment. During the year ended March 31, 2019, we took delivery of 345.7 million barrels of wastewater, an average of 947,000 barrels per day.

Our Water Solutions segment engages in solids disposal with specialized equipment at select facilities in the Eagle Ford shale play, the Permian Basin, and the DJ Basin, which enables us to accept and dispose of solids such as tank bottoms, drilling fluids and drilling muds generated by crude oil and natural gas exploration and production activities. Our facilities will accept only exploration and production exempt waste allowed under our current permits.

Our Water Solutions segment is in the freshwater business in New Mexico and Texas. During the year ended March 31, 2019, we acquired two ranches and four freshwater facilities (including 45 freshwater wells).
Operations. We own 82 water treatment and disposal facilities, including 137 injection wells. The location and permitted processing capacities of these facilities and whether the facilities are located on lands we own or lease are summarized below.
  Number of Permitted Processing Capacity (barrels per day)
Location Facilities Own Lease Total
Permian Basin       

Delaware Basin (1) - Texas and New Mexico 26
 1,431,000
 55,000
 1,486,000
Midland Basin (1) - Texas 15
 400,800
 
 400,800
Eagle Ford (1)(2) - Texas 24
 634,000
 292,000
 926,000
DJ Basin - Colorado 13
 345,500
 150,000
 495,500
Granite Wash (1) - Texas 2
 60,000
 
 60,000
Pinedale Anticline (3) - Wyoming 1
 
 60,000
 60,000
Eaglebine - Texas 1
 20,000
 
 20,000
Total - All Facilities 82
 2,891,300
 557,000
 3,448,300
(1)Certain facilities can dispose of both wastewater and solids such as tank bottoms, drilling fluids and drilling muds.
(2)Includes one facility with a permitted processing capacity of 40,000 barrels per day in which we own a 75% interest.
(3)This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard.

Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline gathering systems and by truck. Our pipeline delivered volumes will continue to

increase as new projects come on line. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water. Our solids customers bring solids generated by crude oil and natural gas exploration and production operations to our facilities by truck.

Our facilities in Colorado, Texas and New Mexico dispose of wastewater primarily into deep underground formations via injection wells.

Our facility servicing the Pinedale Anticline in Wyoming has the assets and technology needed to treat the water more extensively than a typical disposal facility. At this facility, the water is recycled, rather than being disposed of in an injection well. We either process the water to the point where it can be returned to producers to be reused in future drilling operations (recycle quality water), or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem (discharge quality water). Recycling offers producers an alternative to the use of fresh water in hydraulic fracturing operations. This minimizes the impact on aquifers, particularly in arid regions of the United States. Since June 2012, we have recycled approximately 19.4 million barrels (815 million gallons) of recycle quality water, have returned approximately 9.0 million barrels (378 million gallons) of discharge quality water back to New Fork River, which is a tributary of the Colorado River, and have returned approximately 2.6 million barrels (109 million gallons) of water to the ecosystem through an agricultural irrigation system.

At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells.

Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies that conduct drilling operations near our facilities. The customers of our Texas and New Mexico facilities consist of both wastewater transportation companies and producers. The primary customer of our Wyoming facility has committed to deliver a specified minimum volume of water to our facility under a long-term contract. The primary customers of our Colorado facilities have committed to deliver all wastewater produced at wells within the DJ Basin to our facilities. Most customers of our other facilities are not under volume commitments, although many of our facilities have acreage dedications or are connected to producer facilities by pipeline. During the year ended March 31, 2019, 48% of the water treatment and disposal revenues of our Water Solutions segment were generated from our ten largest customers of the segment.

Competition. We compete with other processors of wastewater to the extent that other processors have facilities geographically close to our facilities. Location is an important consideration for our customers, who seek to minimize the cost of transporting the wastewater to disposal facilities. Our facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our Water Solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling and producing new wells.

Pricing Policy. We charge customers a fee per barrel of wastewater processed. Certain contracts require the customer to deliver a specified minimum volume of wastewater over a specified period of time. We also generate revenue from the sale of hydrocarbons we recover in the process of treating the wastewater, which we take into consideration in negotiating the processing fees with our customers. We also charge pipeline transportation fees, pipeline interconnection fees and solids disposal fees to our customers.

Billing and Collection Procedures. Our Water Solutions customers consist of large exploration and production companies and also wastewater transportation companies and producers. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on these customers. We believe the following procedures enhance our collection efforts with these customers:

we require certain customers to prepay or place deposits for our services;
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;
we review receivable aging analyses regularly to identify issues or trends that may develop; and
we require our marketing personnel to manage their customers’ receivable position and suspend service to customers that have not timely paid invoices.

Trade Names. Our Water Solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names.


Technology. We hold multiple patents for processing technologies. We believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations.

Liquids

Overview. Our Liquids segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assets owned by us and third parties. Our Liquids business supplies propane to third-party retailers and wholesalers and butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing their seasonal butane supply needs. During the year ended March 31, 2019,2022, we sold 2.5approximately 2.8 billion gallons of natural gas liquids, an average of 6.83refined products and renewables products, or 7.61 million gallons (approximately 181,000 barrels) per day.

Operations. We procure natural gas liquids from refiners, natural gas processing plants, producers and other resellers for delivery to leased or owned storage space, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transport vehicles from common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar.

A portion of our wholesale propane gallons are presold to third-party retailers and wholesalers at a fixed price under back-to-back contracts. Back-to-back contracts, in which we balance our contractual portfolio by buying physical propane supply or derivatives when we have a matching purchase commitment from our wholesale customers, protect our margins and mitigate commodity price risk. Presales also reduce the impact of warm weather because the customer is required to take delivery of the propane regardless of the weather or any other factors. We generally require cash deposits from these customers. In addition, on a daily basis we have the ability to balance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipeline inventory transfers at major storage hubs.

In order to secure consistent supply during the heating season, we are often required to purchase volumes of propane during the entire fiscal year. In order to mitigate storage costs and price risk, we may sell those volumes at a lesser margin in lower demand months than we earn in our other wholesale operations.

We purchase butane from refiners during the summer months, when refiners have a greater butane supply than they need, and sell butane to refiners during the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage to store butane for this purpose.

We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee as well as subleasingsublease railcars to certain customers.

We own 27 natural gas liquids Our owned and leased terminals and we lease arailcar fleet of approximately 4,600 high-pressure and general purpose railcars (of which 125 railcars are subleased to third parties). These assets give us the opportunity to access wholesale markets throughout the United States, and to move product to locations where demand is highest. We utilize these terminals and railcars primarily in the service of our wholesale propane, butane and asphalt operations. At the underground storage facility near Delta, Utah, and our facilities at Kingfisher, Oklahoma and Port Hudson, Louisiana, we provide transportation, storage, and throughput services to third parties.


The location ofparties at our facilities (excluding the underground storage facility near Delta, Utah) and their throughput capacity are summarized below.
Facility
Throughput Capacity
(gallons per day)
Terminal Interconnects
Arkansas2,422,800
Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility
Missouri1,813,000
Connected to Phillips66 Blue Line Pipeline
Minnesota1,441,000
Connected to Enterprise Mid-America Pipeline; Rail Facility
Indiana1,364,000
Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility
Louisiana945,000
Truck Facility
Illinois864,000
Connected to Phillips66 Blue Line Pipeline
Wisconsin863,000
Connected to Enterprise Mid-America Pipeline; Rail Facility
Oklahoma756,800
Connected to Phillips66 Chisholm Pipeline; Rail Facility
Washington717,000
Rail Facility
Virginia684,000
Rail Facility; Marine Facility
Massachusetts681,200
Rail Facility
Vermont387,000
Rail Facility
Maine386,400
Rail Facility
New York386,400
Rail Facility
Pennsylvania368,000
Rail Facility
United States Total14,079,600
Ontario, Canada200,000
Truck Facility
Canada Total200,000
Total14,279,600

We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that expires in November 2022. The terminal in St. Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement.

We own the land on which 13 of the 27 natural gas liquids terminals are located and we either have easements or lease the land on which the remaining terminals are located.

We are the majority owner of an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 6.0 million barrels of natural gas liquids and refined products. We lease storage to approximately 16 customers, with lease terms ranging from one to three years. The facility is located on property for which we have a long-term lease.

We own a natural gas liquids terminal that supports refined products blending inat Port Hudson, Louisiana and a natural gas liquids and condensate facility in Kingfisher, Oklahoma. The Port Hudson Terminal is located near Baton Rouge, Louisiana, and is in proximity to other refined products infrastructure along the Colonial pipeline. This truck unloading and storage facility allows for the aggregation and supply of butane and naphtha for motor fuel blending and consists of storage tanks with total capacity of 720,000 gallons. The Kingfisher Facility is a natural gas liquids and condensate facility located in Kingfisher, Oklahoma, which is located in the middle of the STACK production region. The facility connects to the Chisholm NGL pipeline and the Conway Fractionation complex and consists of 450,000 gallons of storage capacity, a methanol extraction tower and a 5,000-barrel per day condensate splitter.

In March 2019, we completed the acquisition of the natural gas liquids terminal business of DCP Midstream, LP. The acquisition consisted of five propane rail terminals, located in the Eastern United States, a 50% ownership interest in an additional rail terminal, located in the state of Maine, and an import/export terminal located in Chesapeake, Virginia. The import/export terminal has the capability to load and unload ships ranging in size from handy-sized vessels up to very large gas carriers. These terminals complement our existing natural gas liquids portfolio and also create additional opportunities for new

and existing customers to supply their business. The terminals we purchased in this acquisition are included in the throughput capacity per day table above.

We own 23 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

We lease natural gas liquids storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers. We lease storage space for natural gas liquids in various storage hubs in Kansas, Mississippi, Missouri, Texas and Canada.

The following table summarizes our significant leased storage space at natural gas liquids storage facilities and interconnects to those facilities:
  
Leased Storage Space
(gallons)
  
Storage Facility 
Beginning
April 1,
2019
 
At
March 31,
2019
 Storage Interconnects
Kansas 67,200,000
 67,200,000
 Connected to Enterprise Mid-America Pipeline, NuStar Pipelines and ONEOK North System Pipeline; Rail Facility; Truck Facility
Mississippi 6,300,000
 9,660,000
 Connected to Enterprise Dixie Pipeline; Rail Facility
Missouri 7,560,000
 7,560,000
 Truck Facility
Texas 3,990,000
 6,510,000
 Connected to Enterprise Texas Eastern Products Pipeline; Truck Facility
Michigan 1,050,000
 
 Rail Facility; Truck Facility
United States Total 86,100,000
 90,930,000
  
       
Ontario, Canada 15,750,000
 23,179,000
 Rail Facility
Alberta, Canada 3,440,800
 3,441,000
 Connected to Cochin Pipeline; Rail Facility
Canada Total 19,190,800
 26,620,000
  
       
Total 105,290,800
 117,550,000
  

Customers. Our Liquids business serves approximately 950 customers in 47 states. Our Liquids business serves national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. We deliver the propane supply to our customers at terminals located on common carrier pipelines, rail terminals, refineries, and major United States propane storage hubs. During the year ended March 31, 2019, 27% of the revenues of our Liquids segment were generated from our ten largest customers of the segment.

Seasonality. Our wholesale Liquids business is largely seasonal as the primary users of propane as heating fuel generally purchase propane during the typical fall and winter heating season. However, we are able to partially mitigate the effects of seasonality by preselling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take delivery of the product regardless of the weather.

Competition. Our Liquids business faces significant competition, as many entities, including other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (such as terminal and refinery operations), are engaged in the liquids business, some of which have greater financial resources than we do. The primary factors on which we compete are:

price;
availability of supply;
reliability of service;
available space on common carrier pipelines;
storage availability;

logistics capabilities, including the availability of railcars, and proprietary terminals;
long-term customer relationships; and
the acquisition of businesses.

Pricing Policy. In our Liquids business, we offer our customers three categories of contracts for propane sourced from common carrier pipelines:

customer pre-buys, which typically require deposits based on market pricing conditions;
market based, which can either be a posted price or an index to spot price at time of delivery; and
load package, a firm price agreement for customers seeking to purchase specific volumes delivered during a specific time period.

We use back-to-back contracts for many of our Liquids segment sales to limit exposure to commodity price risk and protect our margins. We are able to match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However, certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes are not matched with a sales commitment.

We generally require deposits from our customers for fixed price future delivery of propane if the delivery date is more than 30 days after the time of contractual agreement.

Billing and Collection Procedures. Our Liquids segment customers consist of commercial accounts varying in size from local independent distributors to large regional and national retailers. These sales tend to be large volume transactions that can range from 10,000 gallons up to 1,000,000 gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on these customers. We believe the following procedures enhance our collection efforts with these customers:

we require certain customers to prepay or place deposits for their purchases;
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;
we require certain customers to take delivery of their contracted volume ratably to help control the account balance rather than allowing them to take delivery of propane at their discretion;
we review receivable aging analysis regularly to identify issues or trends that may develop; and
we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

Trade Names. Our Liquids segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Sawtooth Caverns, Centennial Energy, and Centennial Gas Liquids trade names.

Refined Products and Renewables

Overview. Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. In addition, in certain storage locations, our Refined Products and Renewables segment may also purchase unfinished gasoline blending components for subsequent blending into finished gasoline to supply our marketing business as well as third parties. During the year ended March 31, 2019, we sold 173.5 million barrels of gasoline, 53.7 million barrels of diesel, 2.6 million barrels of ethanol and 1.0 million barrels of biodiesel.

Operations. The refined products we handle include gasoline, diesel, and heating oil. We purchase refined petroleum and renewable products primarily in the Gulf Coast, SoutheastWest Coast and Midwest regions of the United States and schedule them for delivery at various locations throughout the country. On certain interstate refined products pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historical shipment volumes. We hold allocated capacity on the Colonial and Plantation pipelines.

A significant percentageconduct just-in-time sales at a nationwide network of our business is priced on a back-to-back basis which minimizes our commodity price exposure. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at terminals owned by third

parties. As discussed in “Dispositions” above, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. As part of this transaction, we retained TransMontaigne Product Services LLC, including its marketing business, customer contracts and its line space on the Colonial and Plantation pipelines, which is a significant part of our Refined Products and Renewables segment. We also entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system.

The following table summarizes our leased storage space at refined products storage facilities:
Locations
Active Storage Capacity
(shell barrels)
Southeast Facilities
Virginia2,288,000
Georgia1,953,000
Mississippi1,594,000
New Jersey1,281,000
North Carolina775,000
Alabama178,000
South Carolina166,000
Florida62,000
Total Southeast Facilities Storage Capacity (1)8,297,000
Mid-Continent Facilities
Magellan North system985,000
NuStar East Products system390,000
Total Mid-Continent Facilities Storage Capacity1,375,000
West Facilities
Kinder Morgan (Phoenix, Arizona)50,000
Buckeye Terminals, LLC1,000
Total West Facilities Storage Capacity51,000
Total Facilities Storage Capacity9,723,000
(1)Includes 235,400 barrels of capacity that is subleased to third parties.

In January 2019, we acquired two refined products terminals located in Georgia. These terminals have a combined refined products storage capacity of 170,000 shell barrels, ethanol storage capacity of 23,000 shell barrels and transmix storage capacity of 900 shell barrels.

We purchase ethanol primarily at production facilities in the Midwest and transport the ethanol via trucks and railcars for sale at various locations. We also blend ethanol into gasoline for sale to customers at third party terminals. We market and handle logistics for third-party ethanol manufacturers for a service fee. We primarily purchase biodiesel from production facilities in the Midwest and in Houston, Texas, and transport the biodiesel via railcar to sell to customers. We lease 22,000 barrels of biodiesel storage at a fuel terminal in Phoenix, Arizona and also have a biodiesel terminaling agreement at a fuel terminal in Phoenix, Arizona with a minimum monthly throughput requirement. We lease 346 railcars for the transportation of renewables, of which 299 railcars are subleased to a third party.

Customers. Our Refined Products and Renewables segment serves customers in 37 states. During the year ended March 31, 2019, 40% of the revenues of our Refined Products and Renewables segment were generated from our ten largest customers of the segment. We sell to customers parties via rack spot sales contract sales, bulk sales, and just-in-time sales.

Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with local market wholesalers, independent gasoline station chains, heating oil suppliers, and other customers. Contract sales provide these customers with a specified volume of product during the term of the agreement.

Delivery of product sold under these arrangements generally is at third party truck racks. The pricing of the productor delivered under a majority of our contract sales is based on published index prices, and varies based on changes in the applicable indices. In addition, at the customer’s option, the contract price may be fixed at a stipulated price per gallon.

Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks. At the end of each day for each of the terminals that we market from, we establish the next day selling price for each product for each of our delivery locations. We announce or “post” to customers via website, e-mail, and telephone communications the rack spot sale price of various products for the following morning. When customers decide to purchase product from us, we purchase the same volume of product from a supplier at a previously agreed-upon price. For these just-in-time transactions, our purchase from the supplier occurs at the same time as our sale to our customer. Typical rack spot sale purchasers include commercial and industrial end users, independent retailers and small, independent marketers who resell product to retail gasoline stations or other end users. Our selling price of a particular product on a particular day is a function of our supply at that delivery location or terminal, our estimate of the costs to replenish the product at that delivery location, and our desire to reduce inventory levelsproduct volume at that particular location that day. A significant percentage of our business is priced on a back-to-back basis which minimizes our commodity price exposure.

Bulk sales generally involve
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The following table summarizes the salelocation of our facilities and respective storage capacity and interconnects to those facilities.
Storage Capacity (in gallons)
LocationNumber of FacilitiesOwn (1)Lease (2)TotalTerminal Interconnects
Virginia20,720,000 — 20,720,000 Rail Facility; Marine Facility
Arkansas3,765,000 90,000 3,855,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility
Minnesota1,829,000 — 1,829,000 Connected to Enterprise Mid-America Pipeline; Rail Facility
Missouri1,770,000 — 1,770,000 Connected to Phillips66 Blue Line Pipeline
Indiana1,530,000 — 1,530,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility
Wisconsin714,000 390,000 1,104,000 Connected to Enterprise Mid-America Pipeline; Rail Facility
Massachusetts668,400 120,000 788,400 Rail Facility
Louisiana720,000 — 720,000 Truck Facility
Washington300,000 355,000 655,000 Rail Facility
Illinois480,000 — 480,000 Connected to Phillips66 Blue Line Pipeline
Michigan480,000 480,000 Connected to Ambassador Pipeline
New York— 270,000 270,000 Rail Facility
Pennsylvania180,000 — 180,000 Rail Facility
Maine— 120,000 120,000 Rail Facility
Vermont— 120,000 120,000 Rail Facility
United States Total23 33,156,400 1,465,000 34,621,400 
Ontario, Canada— 120,000 120,000 Truck Facility
Canada Total— 120,000 120,000 
Total24 33,156,400 1,585,000 34,741,400 
(1)    These facilities are located on lands we own.
(2)    These facilities are located on lands we lease.

We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that expires in November 2022. The terminal in St. Catharines, Ontario, Canada is operated by a third party under a year-to-year agreement.

We own the land on which 15 of the 24 natural gas liquids terminals are located and we either have easements or lease the land on which the remaining terminals are located.

We own a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a marine export/import terminal in Norfolk, Virginia. The Port Hudson terminal is located near Baton Rouge, Louisiana, and is in proximity to other refined products infrastructure along the Colonial pipeline. This truck unloading and storage facility allows for the aggregation and supply of butane and naphtha for motor fuel blending and consists of storage tanks with a total capacity of 720,000 gallons. The Chesapeake facility is a marine export/import terminal situated upstream of Norfolk, Virginia on the Elizabeth River. The site includes a proprietary dock with the capacity to berth handy-sized vessels (a dry bulk carrier of an oil tanker with a capacity between 15,000 and 35,000 dead weight tonnage) to very large quantitiesgas carriers (a carrier capable of loading anywhere between 100,000 cubic meters to 200,000 cubic meters of natural gas), truck loading and off-road racks along with 22 railcar spots, with service provided by Norfolk Southern Railroad. The facility has an aggregate storage capacity of 20,378,000 gallons.

We own 25 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

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We own the Ambassador Pipeline, an approximately 225-mile propane pipeline, which runs from the Kalkaska gas plant in Kalkaska County, Michigan to a termination point near Marysville in St. Clair County, Michigan. We are currently working on a Marysville, Michigan connection, which has an estimated completion date of June 2022 and will allow the Ambassador Pipeline to be fully operational. The Wheeler propane terminal, in central Michigan, was fully permitted and operational on February 1, 2022. These assets complement our existing assets in the major cashupper Midwest and will expand our presence in Michigan, one of the top propane markets includingin the Houston Gulf Coast and New York Harbor. A bulk sale of products also may be made while the product is being transported on common carrier pipelines.United States.

We conduct just-in-time sales atutilize a nationwide networkfleet of terminals ownedapproximately 4,400 high-pressure and general purpose leased railcars of which 34 railcars are subleased by third parties.

We post priceslease storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers.

The following table summarizes our significant leased storage space at eachnatural gas liquids and refined products storage facilities and interconnects to those facilities:
Leased Storage Space
(in gallons)
Storage Facility LocationBeginning
April 1,
2022
At
March 31,
2022
Storage Interconnects
Kansas56,700,000 56,700,000 Connected to Enterprise Mid-America Pipeline, NuStar Pipelines and ONEOK North System Pipeline; Rail Facility; Truck Facility
Michigan22,260,000 10,500,000 Rail Facility; Truck Facility
Utah8,400,000 22,050,000 Rail Facility
Missouri7,560,000 7,560,000 Truck Facility
Arizona7,056,000 7,056,000 Rail Facility; Truck Facility
Texas4,410,000 4,410,000 Connected to Enterprise Texas Eastern Products Pipeline; Truck Facility
Mississippi2,100,000 2,520,000 Connected to Enterprise Dixie Pipeline; Rail Facility
Oregon554,400 554,400 Connected to Kinder Morgan Pipeline and Olympic Pipeline
United States Total109,040,400 111,350,400 
Ontario, Canada8,467,200 15,750,000 Rail Facility
Alberta, Canada3,970,092 3,440,800 Connected to Cochin Pipeline; Rail Facility
Canada Total12,437,292 19,190,800 
Total121,477,692 130,541,200  

Customers. Our Liquids Logistics segment serves approximately 1,300 customers in 48 states, Mexico and Canada, including national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. During the year ended March 31, 2022, 22% of these locations on a daily basis. Whenthe revenues of our Liquids Logistics segment were generated from our ten largest customers decide to purchase product from us, we purchaseof the same volume of product from a supplier at a previously agreed-upon price. For these just-in-time transactions, our purchase from the supplier occurs at the same time as our sale to our customer.segment.

Seasonality. Our wholesale liquids business is largely seasonal as the primary users of propane as heating fuel generally purchase propane during the typical fall and winter heating season. However, we are able to partially mitigate the effects of seasonality by preselling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take delivery of the product regardless of the weather.

The demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months. However, the demand for diesel typically peaks during the fall and winter months due to colder temperatures, in the Northeast, and peaks in the Midwest during spring planting and fall harvest.

Competition. Our Refined Products and Renewables businessLiquids Logistics segment faces significant competition as many entities are engagedfrom other natural gas liquids wholesalers, trading companies and companies involved in the refined productsnatural gas liquids midstream industry (such as terminal and renewables business,refinery operations), some of which have greater financial resources than we do. The primary factors on which we compete are:

price;
availability of supply;
14


reliability of service;
available space on common carrier pipelines;
storage availability;
logistics capabilities, including the availability of railcars, and proprietary terminals; and
long-term customer relationships.

Market Price Risk.Risk. Our philosophy is to maintain minimum commodity price exposure through a combination of purchase contracts, sales contracts and financial derivatives. A significant percentage of our businessrefined products and biodiesel businesses is priced on a back-to-back basis which minimizes our commodity price exposure. For discretionary inventory, and for those instances where physical transactions cannot be appropriately matched, we utilize financial derivatives to mitigate commodity price exposure. Specific exposure limits are mandated in our credit agreement and in our market risk policy.

The value of refined products in any local delivery market is the sum of the commodity price as reflected on the NYMEX New York Mercantile Exchange (“NYMEX”) and the basis differential for that local delivery market. The basis differential for any local delivery market is the spread between the cash price in the physical market and the quoted price in the futures markets for the prompt month. We typically utilize NYMEX futures contracts to mitigate commodity price exposure. We generally do not manage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions.

Pricing Policy. In our Liquids Logistics segment, we offer our customers the following categories of contracts:

customer pre-buys, which typically require deposits based on market pricing conditions;
market based, which can either be a posted price or an index to spot price at time of delivery; and
load package, a firm price agreement for customers seeking to purchase specific volumes delivered during a specific time period.

We use back-to-back contracts for many of our liquids business sales to limit exposure to commodity price risk and protect our margins. We are able to match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However, certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes are not matched with a sales commitment.

We generally require deposits from our customers for fixed price future delivery if the delivery date is more than 30 days after the time of contractual agreement.

Legal and Regulatory ConsiderationsConsiderations. . Demand for ethanol and biodiesel is driven in large part by government mandates and incentives. Refiners and producers are required to blend a certain percentage of renewables into their refined products, although the percentage can vary from year to year based on the United States Environmental Protection Agency (“EPA”) mandates. In addition, the federal government has in recent years granted certain tax credits for the use of biodiesel, although on several occasions these tax credits have expired. In February 2018,December 2019, the federal government passed a law to reinstate the tax credit retroactively to January 1, 2017,2018, with the credit expiring on December 31, 2017. Legislation is pending

in Congress (e.g., H.R. 2089 proposed by Representative Abby Finkenauer (D-IA) and S. 1288 proposed by Senator Ron Wyden (D-OR) that would, if passed and signed into law, further extend these tax credits.2022. Changes in future mandates and incentives, or decisions by the federal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel.

Billing and Collection Procedures
. Our Refined Products and Renewables customers consist primarily of commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our Refined Products and Renewables customers. We believe the following procedures enhance our collection efforts with our customers:

we require certain customers to prepay or place deposits for our products and services;
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;
we monitor individual customer receivables relative to previously-approved credit limits, and our automated rack delivery system gives us the option to discontinue providing product to customers when they exceed their credit limits;
we review receivable aging analyses regularly to identify issues or trends that may develop; and
we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

Trade Names. Our Refined Products and RenewablesLiquids Logistics segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Centennial Energy, NGL Crude Logistics and TransMontaigne Product Services LLCCentennial Gas Liquids trade names.

EmployeesHuman Capital

At March 31, 2019,2022, we had approximately 1,300842 employees in 28 states and Canada. Of those employees, 220 provide work primarily for our Water Solutions segment, 245 provide work primarily for our Crude Oil Logistics segment, 169 provide work primarily for our Liquids Logistics segment, and 208 provide administrative services to the various business segments. NGL is an equal-opportunity employer, and our employee handbook underscores that commitment, with policies prohibiting discrimination, harassment, and retaliation.

We understand the importance of competitive benefits packages for the health and welfare of our employees and for our ability to recruit and retain the best talent. In that regard, at the end of fiscal year 2021, we implemented $20 per hour
15


minimum wage for all regular, full-time employees. We doMore than 95% of our eligible employees participate in the NGL 401(k) Plan, and we increased our employer match in our 401(k) Plan in fiscal year 2021. In addition, we provide access to a traditional PPO, or a high-deductible medical plan including a health savings account with employer contributions; a flexible spending account option for those not have anyenrolled in the high-deductible medical plan; a dental plan; a vision plan; an Employee Assistance Plan including free counseling for employees that areand members of a labor union.

their household; company-paid short-term disability coverage; voluntary long-term disability coverage; company-paid life and AD&D coverage; and voluntary life and AD&D coverage options for employees and their family members.

Our operations are guided by specific health and safety protocols. We endeavor to conduct our business in a manner that meets or exceeds applicable health and safety regulations and minimizes risk, both to our employees and the communities where we operate. Our environmental, health and safety team:

•    Advises on safety and industrial hygiene regulatory requirements and best practices;
•    Develops safety procedures and guidelines;
•    Conducts safety inspections;
•    Advises on strategies to improve safety and health performance; and
•    Designs and conducts safety and industrial hygiene training courses.

As part of this effort, we have implemented an enterprise management information system designed to help us achieve a better understanding of our performance, identify root causes of incidents, and where appropriate, implement necessary mitigations.

Government Regulation


Regulation of the Oil and Natural Gas Industries

Regulation of Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and natural gas liquids are not currently regulated and are transacted at market prices. In 1989, the United States Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. The Federal Energy Regulatory Commission (“FERC”), which has authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all natural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or the FERC (with respect to the resale of natural gas in interstate commerce), however, could re-impose price controls in the future.

Exploration and production operations and water disposal facilities are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations, and conservation of resources. While theseThese regulations do not directly apply tomay affect our business, they may affectbusinesses and the businesses of certain of our customers and suppliers and thereby indirectly affectsuppliers. It is not possible to predict how or when regulations affecting our business.operations or our customers’ or suppliers’ operations might change.

Regulation of the Transportation and Storage of Natural Gas and Oil and Related Facilities. The FERC regulates oil pipelines under the Interstate Commerce Act and natural gas pipeline and storage companies under the Natural Gas Act, and Natural Gas Policy Act of 1978 (the “NGPA”), as amended by the Energy Policy Act of 2005. The Grand Mesa Pipeline became operational on November 1, 2016 and has several points of origin in Colorado, runs from those origin points through Kansas and terminates in Cushing, Oklahoma. The transportation services on the Grand Mesa Pipeline are subject to FERC regulation. In February 2018, the FERC issued a revised policy to disallow income tax allowance cost recovery in rates charged by pipeline companies organized as master limited partnerships. The FERC’s revised policy impacts cost-of-service rates on oil pipelines. Currently, the volumes of crude oil that are transported on the Grand Mesa Pipeline are subject to contractual agreements. Therefore, the FERC’s revised policy ishas not expected to impactimpacted the Grand Mesa Pipeline at the present time. Additionally, contracts we enter into for the interstate transportation or storage of crude oil or natural gas may be subject to FERC regulation including reporting or other requirements. In addition, the intrastate transportation and storage of crude oil

and natural gas is subject to regulation by the state in which such facilities are located, and such regulation can affect the availability and price of our supply, and have both a direct and indirect effect on our business.

Anti-Market Manipulation. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, which authorizes the FERC to impose fines of up to $1 million per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the
16



Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1 million per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission (“CFTC”) is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1 million per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation throughBecause our barge fleet transports between locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensure that no violation ofcompliance with the Jones Act ownership restrictions occurs.Act. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience.

Environmental Regulation

General. Our operations are subject to stringent and complexa myriad of federal, state and local laws and regulations relating to the protection of the environment. Accordingly, we must comply with these lawsExisting regulatory structure shapes our decision-making and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

requiring the installationshaping decisions regarding what types of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;to deploy and how a facility should be designed;
limiting or prohibitinginforming decision-making regarding construction activities, insuch as where to locate and where not to locate a facility; e.g., locating construction activities away from sensitive environmental, cultural or historic areas, such asincluding wetlands, coastal regions or areas inhabited by endangered or threatened species, and limiting or prohibiting construction activities during certain sensitive periods, such as when threatened or endangered species are breeding/nesting;
delayinginforming decision-making regarding the timing of activities, for example, we will delay construction or system modification or upgrades during permitthe issuance or renewal;renewal periods of certain permits;
requiring investigatoryinforming decision-making pertaining to our approach to investigating, mitigating and remedial actions to mitigate pollution conditions caused byremediating unplanned releases from our facilities and operations or attributable to former operations;facilities or operations, as necessary and appropriate; and
enjoining the operationsshaping our decision-making about whether a facility or operation should be temporarily halted to address potential non-compliance with relevant permit requirements.

Consideration of facilities deemedand compliance with relevant environmental regulatory requirements has led our business activities to be in non-compliance with permits or permit requirements issued pursuantmore sustainable while simultaneously mitigating exposure to or imposed by suchlong and short-term environmental laws and regulations.

Failurerisk. Conversely, failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict and joint and several liability for costs required to clean up and restore sites where substances such as hydrocarbonscrude oil or wastes have been disposed or otherwise unlawfully released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.


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The following is a discussion of the material environmental laws and regulations that relate to our businesses.

Hazardous Substances and Waste. We are subject to various federal, state, and local environmental laws and regulations governing the storage, distribution, and transportation of natural gas liquids and the operation of bulk storage liquefied petroleum gas (LPG) terminals, as well as laws and regulations governing environmental protection, including those addressing the discharge of materials into the environment or otherwise relating to protection of the environment. Generally, these laws (i) regulate air and water quality, and impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) may result in the suspension or revocation of necessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution resulting from our operations; (v) require remedial measures to mitigate pollution from former or ongoing operations; and (vi) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act “(CAA”), the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act (“CWA”) , the Safe Drinking Water Act, the Oil Spills Prevention and Preparedness Regulations, and comparable state statutes. For example, as a flammable substance, propane is subject to risk management plan requirements under section 112(r) of the federal Clean Air Act.

CERCLA, also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. While natural gas liquids are not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as a hazardous substance. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies, and itstudies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances released into the environment.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardoussolid and non-hazardoushazardous wastes. Under the auspicesa delegation of authority from the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as certain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated as solid waste under RCRA’s less stringent solid waste provisions,Subtitle D, state laws or other federal laws. It is possible, however, that certain wastes now classified as non-hazardous solid waste could be classified as hazardous wastes in the future and thereforethereby be subject to more rigorous and costly disposal requirements. Legislation has been proposed from time to time in Congress to re-categorizeregulate certain oil and natural gas wastes as “hazardous wastes.wastes under RCRA.” Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our consolidated results of operations and financial position.

We currently own or lease properties where hydrocarbons arecrude oil is being or havehas been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbonscrude oil or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbonsthe crude oil and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our consolidated results of operations or financial position.

Oil Pollution Prevention. Our operations involve the shipment of crude oil by barge through navigable waters of the United States. The Oil Pollution Prevention Act imposesof 1990 amended the CWA to impose liability for releases of crude oil from vessels or facilities into navigable waters. If a release of crude oil to navigable waters occurred during shipment or from aan oil terminal, we could be subject to liability under the Oil Pollution Prevention Act. We are not currently aware of any facts, events, or conditions related to oil spills that could materially impact our consolidated results of operations or financial position. In 1973, the EPA adopted oil pollution prevention regulations under the Clean Water Act.CWA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or

consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities
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into or upon the navigable waters of the United States. SPCC requirements under the CWA require appropriate containment berms and similar structures to help prevent the discharge of pollutants into regulated waters in the event of a crude oil or other constituent tank spill, rupture or leak. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility(intra-facility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. Where applicable, we strive to maintain and implement suchSPCC plans for our facilities.

Air Emissions. Our operations are subject to the federal Clean Air ActCAA and comparable state and local laws and regulations. These laws and regulations, which regulate emissions of air pollutants from various industrial sources and also impose variousmandate certain permitting, monitoring, recordkeeping and reporting requirements. Such lawsThe CAA and its implementing regulations may require that we obtain permits prior to the construction, modification or modificationoperation of certain projects or facilities expected to produce or significantly increase air emissions above certain threshold levels, that we obtain and strictly comply with air permits containing various emissions and operational limitations, andor utilize specific emission control technologies to limit emissions. Our failure to comply with theseemissions, any of which could impose significant costs on our business. Violation of CAA requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incurmake certain future capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Water Discharges. Discharges. The Clean Water ActCWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as navigable waters, defined as waters of the United States (“WOTUS”), and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the CWA’s National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. The federal SPCC requirements of federal laws requireprogram requires appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarboncrude oil or other constituent tank spill, rupture or leak. The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404. In addition, the Clean Water ActCWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We maintain a number of discharge permits, some of which may require us to monitor and sample the storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water ActCWA and analogous state laws and regulations.

Underground Injection Control. OurThe underground injection operations are subject toof crude oil and natural gas wastes is regulated by the Underground Injection Control Program, as authorized by the Safe Drinking Water Act, as well as analogousby state lawsprograms focused on the conservation of hydrocarbon resources. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and regulations, which establishto prevent migration of fluid from the injection zone into underground sources of drinking water, as well as to prevent communication between injected fluids and zones capable of producing hydrocarbons. The Safe Drinking Water Act establishes requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our underground injection control (“UIC”) permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.

Under the auspices of the federal UIC program as implemented by states with UIC primacy, regulators, particularly at the state level, are becoming increasingly sensitive to possible correlations between underground injection and seismic activity. Consequently, state regulators implementing both the federal UIC program and state corollaries are heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density or injection facilities as well as the rate and volume of injection.

Hydraulic Fracturing. The undergroundHydraulic fracturing involves the injection of crudewater, sand, and chemicals under pressure into the formation to stimulate oil and natural gas wastes are regulated by the Underground Injection Control Program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.production. We do not conduct any hydraulic fracturing activities. However, a portion of our customers’ crude oil and natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, and our Water Solutions business treats and disposes of wastewaterproduced water generated from crude oil and natural gas production, including production utilizingemploying hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate oil and gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical
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constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control ProgramUIC program and/or require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and the United States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on the environment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards and effluent limitation guidelines for wastewaterproduced water from hydraulic fracturing operations. In addition, some states and local governments have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporary or permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future.


Greenhouse Gas Regulation

There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably methane and carbon dioxide, to global warming.climate change. This growing concern has resulted in a steady stream of legislation considered by Congress to address climate change through a variety of mechanisms, including carbon taxes and carbon cap-and-trade programs. For example, on January 24, 2019, Representative Theodore E. Deutch (D-FL) introduced H.R. 763,in February 2021, the Energy Innovation and Carbon DividendClimate Emergency Act of 2019,2021 was introduced in the House of Representative by Rep. Earl Blumenauer (D-OR) as H.R. 795 and in the Senate by Sen. Bernie Sanders (I-VT), which would imposerequire the President of the United States to declare a fee on the carbon content of fuels, including crude oilnational climate emergency and natural gas, on the producers or importers of such fuels. On April 10, 2019, Senator Sheldon Whitehouse (D-RI) introduced S. 1128, the American Opportunity Carbon Fee Act of 2019, which would impose fees on emissions from natural gas, petroleum products, and coal.take various actions to address climate change. The ultimate outcome of any possible future federal legislative initiatives is uncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases,GHGs, primarily through the planned development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap-and-trade programs.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gasesGHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the EPA to adopt and implement regulations to restrict emissions of greenhouse gasesGHGs under existing provisions of the federal Clean Air Act. On May 12, 2016,CAA. During the Obama Administration, the EPA finalized three rules that regulate greenhouse gasGHG emissions from certain sources in the oil and natural gas industry, including New Source Performance Standards for the Oil and Natural Gas Sector (“GHG NSPS”), which became effective on August 2, 2016. On April 18, 2017,During the EPA announced its intentionTrump Administration, rulemaking was undertaken resulting in a substantial relaxation in the GHG NSPS’s requirements, including those relating to reconsider certain aspects of the rule in response to several administrative reconsideration petitions. On October 15, 2018, the EPA proposed to amend the New Source Performance Standards for the Oil and Natural Gas Sector to, among other things, address fugitive emissions, pneumatic pump standards, and closed vent system certification, requirements.among other things, which were finalized on August 13, 2020. The schedule for when this rulemaking could beBiden Administration announced its intention to review the revisions to the GHG NSPS in President Biden’s January 20, 2021 Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. On November 15, 2021, the EPA issued a proposal to revise the GHG NSPS regulations that, if finalized, is not presently known.would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program. The EPA’s greenhouse gaspublic comment period closed on January 31, 2022, and the EPA has announced its intention to issue a supplemental proposal in 2022 that may expand on or modify the 2021 proposal in response to public input. If these regulations are finalized or other future GHG regulations are more stringent, it could require us to incur costs to reduce emissions of greenhouse gasesGHGs associated with our operations and also could adversely affect demand for the products that we transport, store, process, or otherwise handle in connection with our services.

Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanes and floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990,CAA, new climate change regulations may provide us with a competitive advantage over other sources of energy, such as fuel oil and coal.

The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gasGHG regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

Safety and Transportation

All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws. In others,laws, while in other states, municipalities administer them.these laws. We
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conduct training programs to help ensure that our operations comply with applicable governmental regulations. With respect to general operations, each state in which we operate adopts National Fire Protection Association, Pamphlet Nos. 54 and 58, or comparable regulations, which establish rules and procedures governing the safe handling of propane, and Pamphlet Nos. 30, 30A, 31, 385, and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe that the policies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service and installation operations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002.

Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.

The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain United States crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. In January 2012, the federal government passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). This act provides for additional regulatory oversight of the nation’s pipelines, increases the penalties for violations of pipeline safety rules, and complements the DOT’s other initiatives. The 2011 Pipeline Safety Act increasesincreased the maximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harm from $1 million to $2 million. In addition, this law established additional safety requirements for newly constructed pipelines. The law also provides for (i) additional pipeline damage prevention measures; (ii) allowing the Secretary of Transportation to require automatic and remote-controlled shut-off valves on new pipelines; (iii) requiring the Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detection requirements; (iv) improving the way the DOT and pipeline operators provide information to the public and emergency responders; and (v) reforming the process by which pipeline operators notify federal, state and local officials of pipeline accidents. On June 22, 2016,In recent years, Congress has strengthened PHMSA’s safety authority and repeatedly extended it, most recently in the Protecting Ourour Infrastructure of Pipelines and Enhancing Safety Act of 2016 was enacted, further strengthening PHMSA’s safety authority.2020.

Railcar Regulation

We transport a significant portion of our natural gas liquids, crude oil ethanol and biodiesel via rail transportation, and we own andand/or lease a fleet of crude oil, high-pressure and general purpose railcars for this purpose. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.

The adoption of additional federal, state or local laws or regulations, including any voluntary measures by the rail industry regarding railcar design or crude oil rail transport activities, or efforts by local communities to restrict or limit rail traffic, involving crude oil, could similarly affect our business by increasing compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows.

Occupational Health Regulations

The workplaces associated with our manufacturing, processing, terminal, disposal, storage facilities and distribution facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard. In
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general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, these expenditures cannot be accurately estimated at this time, but we do not expect themcompliance with these standards to have a material adverse effect on our business.

Available Information on our Website

Our website address is http://www.nglenergypartners.com. We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.


In addition, the SEC maintains an internet site (http://www.sec.gov)(www.sec.gov) that contains reports, proxy and information statements and other information related to issuers that file electronically with the SEC.

Item 1A.    Risk Factors

The nature of our business activities subjects us to a wide variety of hazards and risks. The following is a summary and a description of the material risks relating to our business activities that we have identified. In addition to the factors discussed elsewhere in this Annual Report, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, financial condition or results of operations, including our ability to generate cash to fund our operations, repay indebtedness and pay distributions. You should also consider the interrelationship and potential compounding effects if multiple risks are realized. These risks are not the only risks that we face. Our business could be impacted by additional risks and uncertainties not currently known or that we currently believe to be immaterial.

Risk Factor Summary

Risks Related to Liquidity and Financing
We may not have sufficient cash, which depends on cash flow rather than profitability, to enable us to fund our operations, repay indebtedness or pay distributions.
Our substantial indebtedness and restrictions contained in our debt and preferred unit agreements may limit our flexibility to obtain financing to pursue other business opportunities and restrict our current and future operations.
Increasing interest rates could impact our financing costs, common unit price, distributions on our Class B Preferred Units (as defined herein) and Class C Preferred Units (as defined herein) and our ability to issue equity and incur debt.
Risks Related to the Operations of Our Business
Our dependence on the ability and willingness of other parties to explore for and produce crude oil and natural gas.
Declining demand for hydrocarbons, commodity prices and production volumes, inventory risk, the availability of transportation and storage capacity, and increased transportation and leasing costs.
Competition from other midstream, transportation, and terminaling and storage companies.
Interruption of service at our principal storage facilities or on common carrier pipelines or railroads.
Fees charged to customers for products and services may not cover increases in costs.
Risk management procedures and the use of derivative financial instruments.
Reduced demand for our products due to energy efficiency, new technologies and alternative energy sources.
Seasonal weather conditions, including warm winter weather, natural or man-made disasters, pandemics, terrorism and political unrest.
Our ability to successfully complete, integrate and operate accretive acquisitions and organic growth projects.
Constructing new transportation systems and facilities subjects us to construction risks.
Opposition from various groups to the operation of our pipelines and facilities.
Our dependence on the leadership, involvement and retention of key and qualified personnel.
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Risks Related to Regulatory Compliance
Impact of executive orders and federal, state, provincial and local laws and regulations with respect to environmental, including climate change, safety and other regulatory matters, including initiatives relating to our hydraulic fracturing customers and saltwater disposal wells.
FERC jurisdiction over our current and potential future operations.
Governmental regulation and other legal obligations related to privacy, data protection, and data security.
Regulations related to cross-border operations.
Risks Related to Our BusinessPartnership Structure and in an Investment in Us
Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders.
Conflicts of interest by our general partner and its affiliates.
Our unitholders have limited voting rights.
Control of our general partner or the IDRs (as defined herein) may be transferred to a third party.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
Our partnership agreement requires that we distribute all of our available cash.
We may issue additional units without the approval of our unitholders.
Our general partner may elect to cause us to issue common units while also maintaining its general partner interest in connection with a resetting of the target distribution levels related to its IDRs.
Our unitholders liability may not be limited if a court finds that unitholder action constitutes control of our business.
Our unitholders may have liability to repay distributions that were wrongfully distributed to them.
The Preferred Units (as defined herein) give the holders thereof liquidation and distribution preferences over our common unitholders.
The issuance of common units upon exercise of certain warrants would cause dilution to existing common unitholders.
Tax Risks to Our Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes.
Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Additional entity-level taxation by individual states.
The tax treatment of publicly traded partnerships could be subject to potential changes or interpretations.
The IRS (as defined herein) may challenge certain income tax positions, methodologies or treatments that we have taken, and pursuant to the Bipartisan Budget Act of 2015, may make audit adjustments to our income tax returns for tax years beginning after 2017.
Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Certain action we take, such as issuing additional units, may increase a unitholder’s tax liability.
Tax gain or loss on the disposition of our common units could be more or less than expected.
Tax exempt entities and non-United States persons owning our common units face unique tax issues.
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate level income taxes.
A unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units.
There are limits on the deductibility of our losses that may adversely affect our unitholders.
Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Preferred Units than the holders of our common units.
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General Risks
The default by significant customers and counterparties or the loss of one or more significant customers.
Failure to maintain an effective system of internal control, including internal control over financial reporting.
Product liability claims and litigation.
A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties.

Risks Related to Liquidity and Financing

We may not have sufficient cash to enable us to fund our operations, repay indebtedness or pay the minimum quarterly distributiondistributions to our unitholders following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash to enable us to fund our operations, repay indebtedness or pay the minimum quarterly distribution. These distributionsdistributions. The distribution to our common unitholders may only be made from cash available for distribution after the preferred quarterly distribution to which our preferred units are entitled. The amount of cash we can distribute onwill have to fund our unitsoperations, repay indebtedness or pay distributions principally depends on the amount of cash we generate from our operations, not profitability, which will fluctuate from quarter to quarter based on, among other things:

weather conditions in our operating areas;
the cost of crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers;
the volume of wastewaterproduced water delivered to our processing facilities;
disruptions in the availability of crude oil and/or natural gas liquids supply;
our ability to renew leases for storage and railcars;
the effectiveness of our commodity price hedging strategy;
weather conditions across the United States;
the level of competition from other energy providers; and
prevailing economic conditions.

In addition, the actual amount of cash we will have available for distributionto fund our operations, repay indebtedness or pay distributions also depends on other factors, some of which are beyond our control, including:

fluctuations in working capital needs;
the level of capital expenditures we make;
the cost of acquisitions, if any;
restrictions contained in the credit agreement (the “Credit Agreement”),ABL Facility and the indentures governing our outstanding 7.50%7.5% senior notes due 2023, 6.125% senior notes due 2025, and 7.50%7.5% senior notes due 2026 and 2026 Senior Secured Notes (collectively, the “Indentures”) and other debt service requirements;
restrictions contained in the agreements relating to our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) and, 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and 9.00% Class D Preferred Units (“Class D Preferred Units”) (collectively the “Preferred Units”) agreements;;
fluctuations in working capital needs;
our ability to borrow funds and access capital markets;
the amount, if any, of cash reserves established by our general partner; and
other business risks discussed in this Annual Report that may affect our cash levels.

The amountboard of cashdirectors of our general partner decided to temporarily suspend all distributions in order to deleverage our balance sheet until we have available for distributionmeet, among other things, the 4.75 to our unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we realize net income.

The amount1.00 total leverage ratio set forth within the indenture of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we might make cash distributions during periods when we record net losses for financial accounting purposes and we might not make cash distributions during periods when we record net income for financial accounting purposes.


Our future financial performance and growth may be limited by our ability to successfully grow organically and complete accretive acquisitions on economically acceptable terms.

Our ability to complete accretive acquisitions on economically acceptable terms may be limited by various factors, including, but not limited to:

increased competition for attractive acquisitions;
covenantsthe 2026 Senior Secured Notes. This resulted in the Credit Agreement and Indentures that limitsuspension of the amount and types of indebtedness that we may incur to finance acquisitions andquarterly common unit distributions, which may adversely affect our ability to make distributions to our unitholders;
lack of available cash or external capital or limitations on our ability to issue equity to pay for acquisitions; and
possible unwillingness of prospective sellers to accept our common units as consideration and the potential dilutive effect to our existing unitholders caused by an issuance of common units in an acquisition.

There can be no assurance that we will identify attractive acquisition candidates in the future, that we will be able to acquire such businesses on economically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance an acquisition will not adversely affect our ability to make distributions to unitholders. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We may be subject to substantial risks in connectionbegan with the integrationquarter ended December 31, 2020, and operation of acquired businesses, in particular those businessesall preferred unit distributions, which began with operations that are distinct and separate from our existing operations.the quarter ended March 31, 2021.

Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to:
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the inability to successfully integrate the operations of recently acquired businesses;
the assumption of known or unknown liabilities, including environmental liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity, debt or synergies;
mistaken assumptions about sales volume, margin or operational expenses;
unforeseen difficulties operating in new geographic areas or in new business segments;
the diversion of management’s and employees’ attention from other business concerns;
customer or key employee loss from the acquired businesses; and
a potential significant increase in our indebtedness and related interest expense.

We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks associated with a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization of any of these risks could have a material adverse effect on the success of a particular acquisition or our consolidated financial position, results of operations or future growth.

As part of our growth strategy, we may expand our operations into businesses that differ from our existing operations. Integration of new businesses is a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfully integrate acquired businesses into our existing operations may have a material adverse effect on our business, consolidated financial position or results of operations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make such acquisitions or an inability to successfully integrate those operations into our overall business operations. The realization of any of these risks could have a material adverse effect on our consolidated financial position or results of operations.


Our substantial indebtedness may limit our flexibility to obtain financing and to pursue other business opportunities.opportunities and our ability to service our debt could impact operations.

At March 31, 2019,2022, the face amount of our long-term debt was $2.2$3.4 billion. Our level of debt could have important consequences to us, including the following:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations and future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make principal and interest payments on our debt;
lower availability under our ABL Facility caused by a higher level of borrowings on the ABL Facility could make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding ABL Facility borrowings;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic and weather conditions, and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, and we will likelymay need to incur additional debt in order to implement our growth strategy. We may experience adverse consequences from increased levels of debt.

Restrictions in the Credit AgreementABL Facility and Indentures could adversely affect our business, financial position, results of operations, ability to make distributions to unitholders and the value of our common units.

The Credit AgreementABL Facility and Indentures limit our ability to, among other things:

incur additional debt or issue letters of credit;
redeem or repurchase units;
make certain loans, investments and acquisitions;
incur certain liens or permit them to exist;
engage in sale and leaseback transactions;
enter into certain types of transactions with affiliates;
enter into agreements limiting subsidiary distributions;
change the nature of our business or enter into a substantially different business;
merge or consolidate with another company; and
transfer or otherwise dispose of assets.


We arewill be permitted to make distributions to our unitholders under the Credit Agreementonce we meet certain defined metrics and Indentures as long as no default or event of default exists both immediately before and after giving effect to the declaration and payment of the distribution and the distribution does not exceed available cash for the applicable quarterly period. The Credit Agreement and Indentures also contain covenants requiring us to maintain certain financial ratios. See Note 8 to our consolidated financial statements included in this Annual Report for a further discussion.

The provisions of the Credit AgreementABL Facility and Indentures may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the Credit Agreementthese agreements could result in a covenant violation, default or an event of default that could enable our lenders, subject to the terms and conditions, of the Credit Agreement, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secure our debts.debts under our 2026 Senior Secured Notes and ABL Facility. If the
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payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.


The consent we entered into with the holder of a majority of our Class D Preferred Units in connection with the 2026 Senior Secured Notes will restrict our current and future operations.
Increases
In connection with the offering of the 2026 Senior Secured Notes, we were required to obtain a consent (the “Class D Preferred Consent”) from the holder of the majority of our Class D Preferred Units (the “Class D Preferred Majority”) to, among other things, enable us to consummate the transaction. The Class D Preferred Consent modifies certain voting and approval rights granted to the Class D Preferred Majority under our Amended and Restated Partnership Agreement. Specifically, the Class D Preferred Consent requires us to obtain the approval of the Class D Preferred Majority for:

incurrences of indebtedness, other than (i) under the ABL Facility, (ii) the issuance of the 2026 Senior Secured Notes and (iii) certain indebtedness outstanding as of the closing of the transaction;
acquiring or disposing of any assets with an aggregate purchase price of greater than $50.0 million during any fiscal year; and
making investment capital expenditures or expansion capital expenditures in excess of $75.0 million in the aggregate during any fiscal year.

These approval rights supplement the existing approval rights in our Amended and Restated Partnership Agreement for the Class D Preferred Majority. They became effective upon the closing of the transaction and will remain in effect until we are no longer in arrears on the Class D Preferred Unit distributions. Because the 2026 Senior Secured Notes and the ABL Facility will restrict our ability to pay distributions on our Class D Preferred Unit distributions until we meet certain defined metrics, we cannot predict when such actions will no longer be subject to the approval of the Class D Preferred Consent, and there is no certainty that we will be able to obtain such consent. As with other restrictions in the indenture to the 2026 Senior Secured Notes and the ABL Facility, these restrictions may affect our ability to grow in accordance with our long-term strategy.

Increasing interest rates could adversely impact our financing costs and our common unit price, our ability to issue equity or incur debt, for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on our existing and future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. AsWe also have exposure to increases in interest rates through variable rate provisions of our Class B Preferred Units and Class C Preferred Units. In addition, the distribution rates on our Class B Preferred Units and Class C Preferred Units convert from fixed rates to floating rates, beginning on and after July 1, 2022, and on and after April 15, 2024, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.

Moreover, the market price of our common units, like with other yield-oriented securities, our common unit price willmay be impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changesincreases or decreases in interest rates either positive or negative, may affect the yield requirements of investors who invest in our common units, and aunits. A rising interest rate environment could have an adverse impact on our common unit price and our ability to issue equity or incur debt for acquisitions or other purposes and could affect our ability to make payments on our debt obligations and cash distributions at our intended levels.

Risks Related to the Operations of Our Business

Our business depends on the availability of crude oil, natural gas liquids, and refined products in the United States and Canada, which is dependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyond our control.

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond our control.

We depend on the ability and willingness of other entities to make operating and capital expenditures to explore for, develop, and produce crude oil and natural gas in the United States and Canada, and to extract natural gas liquids from natural gas, as well as the availability of necessary pipeline transportation and storage capacity. Customers’ expectations of lower
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market prices for crude oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual market conditions and producers’ expectations of market conditions for crude oil and natural gas liquids may also cause producers to curtail spending, thereby reducing business opportunities and demand for our services.

Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce crude oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for crude oil and natural gas, environmental restrictions on the exploration and production of crude oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in crude oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new crude oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger crude oil and natural gas prices, to the extent existing production is not replaced.

The crude oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs, the rate at which it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for crude oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for crude oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could materially and adversely affect our consolidated results of operations.operations and in addition to impacting our business, financial condition and results of operations could require us to incur impairment charges against the associated assets or the write down of our goodwill.

Declining crude oil prices and crude production volumes could adversely impact our Water Solutions and Crude Oil Logistics businesses.segments.

Crude oil spot and forward prices experienced a sharp decline during the second half of calendar year 2014. While crude oil prices have rebounded from the lows experienced during the first three months of calendar year 2016, they are still well below the prices from the first half of calendar year 2014. This has had an unfavorable impact on the revenues of our Water Solutions business. The volume of water we process and crude oil we transport is driven in large part by the level of crude oil production andin the lowerareas in which we operate. Lower crude oil prices have givenprovide the producers with less incentive to expand production.spend on capital expenditures, which results in fewer drilling rigs and lower amounts of crude oil production, which negatively impacts our crude oil transportation and produced water disposal volumes. In addition, a portion of the revenuesour profitability in our Water

Solutions business is generated from the sale of hydrocarbonscrude oil that we recover when processing wastewater,produced water, and lower crude oil prices have an adverse impact on these revenues.sales if not hedged. A further decline in crude oil prices or a prolonged period of low crude oil prices could have an adverse effect on our Water Solutions business.businesses.

In addition, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production could adversely impact volumes in our Crude Oil Logistics business.

Our profitability could be negatively impacted by price and inventory risk related to our business.

The Crude Oil Logistics and Liquids and Refined Products and Renewables businessesLogistics segments are “margin-based” businesses in which our realized margins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.

Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future delivery obligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third-party consumers, other wholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, and we may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden and extended wholesale price increases could reduce our margins. Conversely, a prolonged decline in product prices could potentially result in a reduction of the borrowing base under our working capital facility,the ABL Facility, and we could be required to liquidate inventory that we have already presold.

One of the strategies of our Refined Products and RenewablesLiquids Logistics segment is to purchase refined products in the Gulf Coast region and toWest Coast and transport the product on the Colonial pipelinethird-party pipelines for sale in the Southeast and East Coast. Spreads between product prices in the Gulf Coast compared to locations along the Colonial pipeline can vary significantly, which can create volatility in our product margins. In addition, weSouthwest. We are subject to the risk of a price decline between the time we purchase refined products and the time we sell the products. We seek to mitigate this risk by entering into
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NYMEX futures contracts. However, price changes in locations where we operate do not correspond directly with changes in prices in the NYMEX futures market, and as a result these futures contracts cannot be perfect hedges of our commodity price risk.

We are affected by competition from other midstream, transportation, and terminaling and storage companies, some of which are larger, and more firmly established and may have greater resources than we do.

We experience competition in all of our segments. In our Liquids Logistics segment, we compete for natural gas liquids supplies and also for customers for our services. Our competitors include major integrated oil companies, other midstream or wholesale marketing companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewable or alternative energy. Our Liquids Logistics segment is also seeing increased competition for supply from international markets. We also face significant competition for refined products supplies and customers for those services.

Our Crude Oil Logistics segment faces significant competition for crude oil supplies and also for customers for our services. These operations also face competition from truckingtransportation companies for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Our Water Solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewaterproduced water treatment businesses.

Our Refined Products and Renewables segment also faces significant competition for refined products and renewables supplies and also for customers for our services.

We can make no assurance that we will compete successfully in each of our lines of business. If a competitor attempts to increase market share by reducing prices, we may lose customers, which wouldcould reduce our revenues.


Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines or railroads we use is interrupted.

We use third-party common carrier pipelines to transport our products and we use third-party facilities to store our products. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain and deliver products. We transport crude oil, natural gas liquids ethanol, and biodiesel by railcar. We do not own or operate the railroads on which these railcars are transported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.

We lease certain facilities and equipment and therefore are subject to the possibility of increased costs to retain necessary land and equipment use.

We do not own all of the land on which our facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if our facilities are not properly located within the boundaries of such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect our business, consolidated results of operations and financial position.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods, including many of our railcars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our consolidated results of operations and cash flows.

Our operations depend on various forms of storage and transportation for receipt and delivery of crude oil, natural gas liquids and refined products.

We own natural gas liquids and crude oil terminals and lease storage capacity from third-party natural gas liquids and refined product terminals. The facilities depend on pipelines, railroads, truck transports, and storage systems that are owned and operated by third parties. Any interruption of service at the terminals, or on pipeline, railroad or lateral connections or adverse change in the terms and conditions of services could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities impact the utilization and
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value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

The fees charged to customers under our agreements with them for the transportation and marketingsale of crude oil, condensate, natural gas liquids, gasoline, diesel, ethanol, and biodiesel and the disposal of produced water may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

Our costs may increase more rapidly than the fees that we charge to customers pursuant to our contracts with them. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the production of or the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs, or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.

Risk management procedures, including the use of financial derivative contracts, cannot eliminate all commodity price risk, basis risk, or risk of adverse market conditions which can adversely affect our financial position and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. We also enter into financial derivative contracts, such as futures, to protect against commodity price risk and, as a component of our overall business strategy, we may increase or decrease from time to time our use of such financial derivative contracts in the future. Our use of such financial derivative contracts could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. Although we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our consolidated results of operations and impair our ability to make payments on our debt obligations or distributions to our unitholders. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale.

Basis risk describes the inherent market price risk created when a commodity of a certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of timingrisk. In a backwardated market (when prices for future deliveries are lower than current prices), timing risk is created. In these instances, physical inventory generally loses value as the price of such physical inventory declines over time. Timing risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our consolidated financial position and results of operations.

Competition from alternative energy sources, energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Competition from alternative energy sources, including electricity, natural gas and renewables, has increased from reduced regulation of many utilities. The gradual expansion of the nation’s natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane. In addition, the national trend toward increased conservation and technological advances, such as installation of improved insulation and the development of more efficient furnaces and other appliances, has adversely affected the demand for propane. Future expansion of alternative energy sources, conservation measures or technological advances in appliance efficiency, power generation or other devices may reduce demand for propane and cause us to lose customers.

We cannot predict the effect that development of alternative energy sources, increased conservation or new technology may have on our operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil, natural gas, and natural gas liquids.
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Reduced demand for refined products could have an adverse effect on our results of operations.

Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease in market demand include:

a recession, rising inflation, or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and
the increased use of alternative fuel sources, such as battery-powered engines.

Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business, financial position and results of operations.

We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our business, consolidated financial position, results of operations and cash flows.

Weather conditions, including warm winters or dry or warm weather in the harvest season, may reduce the demand for propane, which could have a material adverse effect on our results of operations, cash flows, financial condition or liquidity.

Weather conditions have a significant impact on the demand for propane for heating and agriculture purposes. Accordingly, our sales volumes of propane are highest during the five-month winter-heating season of November through March and are directly affected by the temperatures during these months. Actual weather conditions can vary substantially from year to year, which may significantly affect our financial performance or condition. Furthermore, variations in weather in one or more regions in which we operate can significantly affect our total propane sales volume and therefore our financial performance or condition. The agricultural demand for propane is affected by weather, as dry or warm weather during the harvest season may reduce the demand for propane used in some crop drying applications.

The widespread outbreak pandemics (like COVID-19) or any other public health crises that impacts the global demand for energy commodities may have material adverse effects on our business, financial position, results or operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the global spread of COVID-19 has caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of the financial and commodity markets. The full extent of the impact of a pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for natural gas liquids, crude oil and refined products (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for energy commodities), produced water disposal services and the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations.

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The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Our future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economically acceptable terms.

Our ability to complete accretive acquisitions on economically acceptable terms may be limited by various factors, including, but not limited to:

increased competition for attractive acquisitions;
covenants in the ABL Facility and Indentures that limit the amount and types of indebtedness that we may incur to finance acquisitions;
the approval of the Class D Preferred Majority;
lack of available cash or external capital or limitations on our ability to issue equity to pay for acquisitions; and
possible unwillingness of prospective sellers to accept our common units as consideration and the potential dilutive effect to our existing unitholders caused by an issuance of common units in an acquisition.

There can be no assurance that we will identify attractive acquisition candidates in the future, that we will be able to acquire such businesses on economically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular, those businesses with operations that are distinct and separate from our existing operations.

Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to:

the inability to successfully integrate the operations of recently acquired businesses;
the assumption of known or unknown liabilities, including environmental liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity, debt or synergies;
mistaken assumptions about sales volume, margin or operational expenses;
unforeseen difficulties operating in new geographic areas or in new business segments;
the diversion of management’s and employees’ attention from other business concerns;
customer or key employee loss from the acquired businesses; and
a potential significant increase in our indebtedness and related interest expense.

We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks associated with a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization of any of these risks could have a material adverse effect on the success of a particular acquisition or our consolidated financial position, results of operations or future growth.

As part of our growth strategy, we may expand our operations into businesses that differ from our existing operations. Integration of new businesses is a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfully integrate acquired businesses into our existing operations may have a material adverse effect on our business, consolidated financial position or results of operations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make
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such acquisitions or an inability to successfully integrate those operations into our overall business operations. The realization of any of these risks could have a material adverse effect on our consolidated financial position or results of operations.

Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.

One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new terminaling, transportation, and produced water treatment facilities. These expansion projects require the expenditure of significant amounts of capital, which may exceed our resources, and involve numerous regulatory, environmental, political and legal uncertainties, including political opposition by landowners, environmental activists and others. There can be no assurance that we will complete these projects on schedule or at all or at the budgeted cost. Our revenues may not increase upon the expenditure of funds on a particular project. Moreover, we may undertake expansion projects to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to undertake expansion projects, which may prove to be inaccurate. As a result, our new facilities and infrastructure may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our consolidated results of operations and financial position.

We may face opposition to the operation of our pipelines and facilities from various groups.

We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, adversely affect our financial condition and the market price of our securities.

Our business plans are based upon the assumption that societal sentiment will continue to enable, and existing regulations will stay intact for, the future development, transportation and use of hydrocarbon-based fuels. Policy decisions relating to the production, refining, transportation and sale of hydrocarbon-based fuels are subject to political pressures, the negative portrayal of the industry in which we operate by the media and others, and the influence and protests of environmental and other special interest groups. Such negative sentiment regarding the hydrocarbon energy industry could influence consumer preferences and government or regulatory actions, which could, in turn, have an adverse impact on our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for hydrocarbon energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects and ongoing operations, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects, as well as properly run our ongoing operations.

We depend on the leadership and involvement of key personnel for the success of our businesses, and we compete with other businesses to attract and retain qualified personnel.

We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our common units. Further, we compete with other businesses to attract and retain qualified employees and a tight labor market may cause our labor costs to increase. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers.

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Risks Related to Regulatory Compliance

Our sales of crude oil, condensate, natural gas liquids, gasoline, diesel, ethanol, and biodiesel and related transportation and hedging activities, and our processing of wastewater,produced water, expose us to potential regulatory risks.

The FTC, the FERC, and the CFTC hold statutory authority to monitor certain segments of the physical and financial energy commodity markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, some of our operations are currently subject to the FERC regulations obligating us to comply with the FERC’s regulations and policies applicable to those assets and operations. Other of our operations may become subject to the FERC’s jurisdiction in the future (see Some of our operations are subject to the jurisdiction of the FERC and other operations may become subject in the future,, below). Any failure on our part to comply with the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business, consolidated results of operations and financial position.

The intrastate transportation or storage of crude oil and refined products is subject to regulation by the state in which the facilities are located and transactions occur. Compliance with these state regulations could have a material and adverse effect on that portion of our business, consolidated results of operations and financial position.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) which was enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. The Dodd-Frank Act provides for statutory and regulatory requirements for derivative transactions, including crude oil, refined and renewable products, and natural gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, the full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. The CFTC has also issued new rules, which became effective on March 15, 2021, that place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. We do not expect the impact of those provisions to have a material effect on us. However, new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.

We are subject to trucking safety regulations, which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). If our current DOT safety ratings are downgraded to “Unsatisfactory”, our business and results of our operations may be adversely affected.

All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on

violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of the company’s operating authority by the FMCSA, which could result in a material adverse effect on our business, consolidated results of operations and financial position and ability to make cash distributions to our unitholders. 

Our business is subject to federal, state, provincial and local laws and regulations with respect to environmental, safety and other regulatory matters and the cost of compliance with, violation of or liabilities under, such laws and regulations could adversely affect our profitability.

Our operations, including those involving crude oil, condensate, natural gas liquids, refined products, renewables, and crude oil and natural gas produced wastewater,water, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs and liabilities due to handling of wastewaterproduced water and hydrocarbons, such as crude oil, condensate, natural gas liquids, gasoline, diesel, ethanol, and biodiesel. For instance, our Water Solutions business carries with it environmental risks, including the risk of leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills. Our Crude Oil Logistics and Liquids and Refined Products and Renewables businessesLogistics segments carry similar risks of leakage and sudden or accidental spills of crude oil, natural gas liquids, and hydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions, fines and penalties, reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.

We use various modes of transportation to carry natural gas liquids, crude oil, refined and renewable products and produced water, including trucks, railcars, barges, and pipelines, each of which is subject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are
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administered by the DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. Railcar accidents within the industry involving trains carrying crude oil from the Bakken region (none of which directly involved any of our business operations), have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by railcar. The introduction of regulations that result in new requirements addressing the type, design, specifications or construction of railcars used to transport crude oil could result in severe transportation capacity constraints during the periods in which new railcars are constructed to meet new specifications or in which the railcars already placed in service are being retrofitted. Our barge transportation operations are subject to the Jones Act, a federal law generally restricting marine transportation in the United States to vessels built and registered in the United States, and manned/owned by United States citizens, as well as setting forth the rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to the transportation of our products and could have an adverse effect on our business.

In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners or operators of our facilities, or for consequences of our or our predecessor’s actions, regardless of whether we were responsible for the release or if such actions were in compliance with all applicable laws at the time of those actions. Also, upon closure of certain facilities, such as at the end of their useful life, we have been and may be required to undertake environmental evaluations or cleanups.

Additionally, in order to conduct our operations, we must obtain and maintain numerous permits, approvals and other authorizations from various federal, state, provincial and local governmental authorities relating to wastewaterproduced water handling, discharge and disposal, air emissions, transportation and other environmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costly operational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizations may involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon our operations.

Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as more stringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations, may adversely impact us, and could result in increased operating

costs and have a material and adverse effect on our activities and profitability. For example, new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our costs for treatment of hydraulic fracturing flowback water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays, interruption or termination of our water treatment operations, all of which could have a material and adverse effect on our consolidated results of operations and financial position.

Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may impose significant costs and liabilities on them. In April 2022, the state of New Mexico adopted new air quality rules that aim to eliminate hundreds of millions of pounds of harmful emissions annually from oil and gas production in New Mexico. Compliance with these new rules is expected to begin in the summer of 2022. Any significant increased costs or restrictions placed on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect on our customers could materially and adversely affect our utilization and profitability by reducing demand for our services. The adoption or implementation of any new regulations imposing additional reporting obligations on greenhouse gasGHG emissions, or limiting greenhouse gasGHG emissions from our equipment and operations, could require us to incur significant costs. As is generally understood regarding the regulatory landscape, there can be no guarantee that these or future rules affecting our operations will not have material effects on our consolidated results of operations and financial position.

Our, our customers’ and our suppliers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, adversely impacting our results of operations and ability to make cash distributions to unitholders, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our crude oil and natural gas exploration and production customers and
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suppliers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden signed executive orders recommitting the United States to the agreement and calling on the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates recently elected to public office. These have included promises to limit emissions and curtail the production of oil and gas, such as through the cessation of leasing public land for hydrocarbon development. For example, on January 27, 2021, President Biden issued an Executive Order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Separately, on January 20, 2021, the Acting Secretary of the United States Department of the Interior issued an order that, among other things, imposed a 60-day moratorium on the issuance of fossil fuel authorizations, including leases and permits, on federal lands. Although the order says it does not limit existing operations under valid leases, on January 27, 2021, President Biden signed an Executive Order indefinitely suspending new oil and gas leasing on federal lands, pending completion of a review of the federal government’s oil and gas permitting and leasing practices. While the United States Department of the Interior announced on April 15, 2022 that it will resume oil and gas leasing on public lands following a federal court’s decision, the topic of oil and gas leasing on public land remains politically fraught, as the announcement indicates that federal land available for oil and gas leasing will be reduced by 80 percent from the acreage originally nominated due to environmental and climate concerns. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas export facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer production laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has applied to join the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our services.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to unitholders.
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Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect our results of operations and ability to make cash distributions to unitholders. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

State and federal legislation and regulatory initiatives relating to our hydraulic fracturing customers could harm our business.

Hydraulic fracturing is a frequentcommon practice inwithin the crude oil and natural gas exploration and production process, including within those fields in whichwhere our Water Solutions segment operates. Hydraulicand Crude Oil Logistics segments operate. The practice of hydraulic fracturing is an important and common process useda well-stimulation technique utilized to facilitate the production of oil and natural gas and other hydrocarbon condensates infrom shale formations, as well asand tight conventional formations. The exploration and production process, including the practice of hydraulic fracturing, process is primarily regulatedsubject to regulation by state oil and gasfederal authorities. ThisJurisdiction and applicable regulatory requirements can vary depending on the location of the activity. The process of hydraulic fracturing has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that the practice could be responsible for incidents of induced seismicity and that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may adversely impact the oil and gas drilling industry. Any current or proposed restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability. For example, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal lands, and on January 27, 2021, the United States Department of the Interior acting pursuant to an Executive Order from President Biden suspended the federal oil and gas leasing program indefinitely. Although the United States Department of Interior recently announced the resumption of onshore oil and gas leasing, the program is being significantly reformed, with 80 percent less land available for leasing from the acreage originally nominated. Actions such as these could have a material adverse effect on us and our industry.

Federal and state legislation and regulatory initiatives relating to saltwater disposal wells could result in increased costs and additional operating restrictions or delays and could harm our business.

The water disposal process is primarily regulated by state oil and gas authorities. This water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increasedcontributed to specific induced seismic activity.events. New laws or regulations, or changes to existing laws or regulations, in response to this perceived threat may adversely impact the water disposal industry.

On certain specific occasions, a state regulatory agency has requestedagencies could request that we suspend operations at a specified disposal facility, pending further study of its potential impact on seismic activity. In one specific instance, we have modifiedlimited the water into a disposal well to redirectand redirected the flow of water to a different area of the geologic formation in order to address such concerns. Recently, in December 2021, as a result of increased seismic activity, the Texas Railroad Commission suspended all deep oil and gas produced water injection in an area which spans approximately 100 square miles in Midland and Ector counties, which directly impacted one of our idled disposal wells. We are currently in the process of plugging and abandoning the idled disposal well.

We cannot predict whether any federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However, any restrictions on water disposal could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform water disposal operations, which would negatively impact our profitability.

Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business, financial position and results of operations.

We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our business, consolidated financial position, results of operations and cash flows.


Risk management procedures cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect our financial position and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. We also enter into financial derivative contracts, such as futures, to manage commodity price risk. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as the price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our consolidated financial position and results of operations.

The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

We encounter risk of counterparty nonperformance in our businesses. Disruptions in the supply of product and in the crude oil and natural gas commodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased gross margins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders.

Our use of derivative financial instruments could have an adverse effect on our results of operations.

We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to do so. We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. In addition, although we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our consolidated results of operations and impair our ability to make payments on our debt obligations or distributions to our unitholders.

Some of our operations are subject to the jurisdiction of the FERC and other operations may become subject in the future.future.

The FERC regulates the transportation of crude oil and refined products on interstate pipelines, among other things. The FERC’s jurisdiction over oil pipelines derives from a 1906 amendment to the Interstate Commerce Act making oil pipelines common carriers subject to federal regulation. The FERC has regulated oil pipelines under this authority since 1977, when legislation transferred jurisdiction to the FERC from the Interstate Commerce Commission. The Energy Policy Act of 1992 directed the Commission to establish a simplified and generally applicable ratemaking methodology for oil pipelines, keeping with the FERC’s statutory mandate to ensure that oil pipelines’ rates are just and reasonable.
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Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by state regulatory commissions, such as the FERC.Railroad Commission of Texas. The distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The Grand Mesa Pipeline became operational on November 1, 2016 and has several points of origin in Colorado, runs from those origin points through Kansas and terminates in Cushing, Oklahoma. The transportation services on the Grand Mesa Pipeline are subject to FERC regulation. Other of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services.

The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. If the FERC’s regulatory reach was expanded to our other facilities, or if we expand our operations into areas that are subject to the FERC’s regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our consolidated results of operations and cash flows.


We are subject to governmental regulation and other legal obligations related to privacy, data protection, and data security. Our actual or perceived failure to comply with such obligations could harm our business.
Volumes
There are numerous laws and regulations regarding privacy and the storage, sharing, use, processing, transfer, disclosure and protection of hydrocarbons recovered duringpersonal data, the wastewater treatment process can vary. Any significant reduction in residual crude oil content in wastewaterscope of which is changing, subject to differing interpretations, and may be inconsistent between states within a country or between countries. For example, the California Consumer Privacy Act (“CCPA”), which went into effect on January 1, 2020, limits how we treat will affect our recovery of hydrocarbonsmay collect and therefore, our profitability.

A portionuse personal data. The effects of the revenues in our Water Solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater. Our ability to recover sufficient volumes of hydrocarbons is dependent upon the residual crude oil content in the wastewater we treat, which is, among other things, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among other things, producers begin recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. Any reduction in residual crude oil content in the wastewater we treat could materiallyCCPA potentially are far-reaching and adversely affect our profitability.

Competition from alternative energy sources may causerequire us to lose customers, thereby negatively impactingmodify our financial positiondata processing practices and results of operations.

Propane competespolicies and incur compliance-related costs and expenses. Further, in November 2020, California voters passed the California Privacy Rights and Enforcement Act (“CPRA”), which expands the CCPA with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gasadditional data privacy compliance requirements that may impact our business, and fuel oil. Competition from alternative energy sources, including electricity, natural gas and renewables, has increased asestablishes a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane in some regions has historically had a competitive price advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gasregulatory agency dedicated to be less expensive than the bulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipeline systems; however, the gradual expansionenforcing those requirements. It remains unclear how various provisions of the nation’s natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in some applicationsCCPA and market demand, propaneCPRA will be interpreted and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other.

We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil, natural gas, and natural gas liquids.

Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

The national trend toward increased conservation and technological advances, such as installation of improved insulation and the development of more efficient furnacesenforced. These and other appliances, has adversely affected the demand for propanedata privacy laws and distillates by retail customers. Future conservation measures or technological advances in appliance efficiency, power generation or other devices may reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

Reduced demand for refined products could have an adverse effect our results of operations.

Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could leadinterpretations continue to a decrease in market demand include:

a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and
the increased use of alternative fuel sources, such as battery-powered engines.


Recent attempts to reduce or eliminate the federal Renewable Fuels Standard (“RFS”), if successful, could adversely impact our results of operations.

The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels. Without these incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our consolidated results of operations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the RFS. The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However, the EPA has authority to waive the requirements of the RFS, in whole or in part, if certain conditions are met. Opponents of the RFS have sought,develop and may continuebe inconsistent from jurisdiction to seek, to force the EPA to reduce or eliminate the RFS. Further, legislation has been introducedjurisdiction. Non-compliance with the goal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPA could adjust the RFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuel products we market, which could adversely impact our consolidated results of operations.

The expiration of tax credits could adversely impact the demand for biodiesel, which could adversely impact our results of operations.

The demand for biodiesel is supported by certain federal tax credits. These tax credits have typically been granted for short durations, and on several occasions these tax credits have expired. In February 2018, the federal government passed a law to reinstate the tax credit retroactively to January 1, 2017, with the credit expiring on December 31, 2017. Legislation is pending in Congress (e.g., H.R. 2089 proposed by Representative Abby Finkenauer (D-IA) and S. 1288 proposed by Senator Ron Wyden (D-OR) that would, if passed and signed into law, further extend these tax credits. There can be no assurance that the federal government will grant such tax credits in the future. If the federal government were to discontinue the practice of granting such tax credits, this would likely have an adverse effect on demand for biodiesel and on our biodiesel marketing operations.

A loss of one or more significant customers could materially or adversely affect our results of operations.

We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customerslaws could result in a substantial loss of revenuespenalties or significant legal liability. Although we take reasonable efforts to comply with all applicable laws and could have a material and adverse effect on our consolidated results of operations. During the year ended March 31, 2019, a significant portion of our revenues was dependent on key customers as summarized below:

79% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment;
48% of the water treatment and disposal revenues of our Water Solutions segment were generated from our ten largest customers of the segment;
27% of the revenues of our Liquids segment were generated from our ten largest customers of the segment); and
40% of the revenues of our Refined Products and Renewables segment were generated from our ten largest customers of the segment.

Certain of our operations are conducted through joint ventures which have unique risks.

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our consolidated results of operations, financial position and cash flows.


Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.

One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new terminaling, transportation, and wastewater treatment facilities. These expansion projects require the expenditure of significant amounts of capital, which may exceed our resources, and involve numerous regulatory, environmental, political and legal uncertainties, including political opposition by landowners, environmental activists and others. Thereregulations, there can be no assurance that we will complete these projects on schedule or at all or at the budgeted cost. Our revenues may not increase upon the expenditure of funds on a particular project. Moreover, we may undertake expansion projects to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to undertake expansion projects, which may prove to be inaccurate. As a result, our new facilities and infrastructure may not be ablesubject to attract enough product to achieve our expected investment return, which could materially and adversely affect our consolidated results of operations and financial position.

We may face opposition to the operation of our pipelines and facilities from various groups.

We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms,regulatory action, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruptionfines, in the operationevent of the affected pipelinean incident. We or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorismour third-party service providers could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities.

Product liability claims and litigation could adversely affect our business and results of operations.

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible liquids. As a result, we are subject to product liability claims and litigation, including potential class actions, in the ordinary course of business. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought against us might not be covered by our insurance policies. In addition, we have self-insured retention amounts which we would have to pay in full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to pay the amount of any settlement or judgment that is in excess of our policy limits. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely affect our business, consolidated results of operations, financial position and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial or operational systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our systemslegislation or regulations are expanded to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our systems. In addition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to increase efficiencyrequire changes in our business. We use various systemsor our third-party service providers’ business practices or if governing jurisdictions interpret or implement their legislation or regulations in our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacksways that negatively affect our facilities,or our customers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt ourthird-party service providers’ business, resulting in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

We lease certain facilities and equipment and therefore are subject to the possibility of increased costs to retain necessary land and equipment use.

We do not own all of the land on which our facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if our facilities are not properly located within the boundaries of such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect our business, consolidated results of operations andor financial position.condition.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods, including many of our railcars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our consolidated results of operations and cash flows.

Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability.

Maintaining a staff of qualified truck drivers is critical to the success of our crude oil logistics operations. We have in the past experienced difficulty in attracting and retaining sufficient numbers of qualified drivers. Regulatory requirements, including the FMCSA’s CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies would create difficulties in increasing the number of our drivers in the event we choose to expand our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meeting customer demands, which could materially and adversely affect our growth and profitability.

If we fail to maintain an effective system of internal control, including internal control over financial reporting, we may be unable to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. We are also subject to the obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to the obligation under Section 404(b) of the Sarbanes Oxley Act of 2002 to engage our independent registered public accounting firm to attest to the effectiveness of our internal control over financial reporting.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective internal control over financial reporting, including our disclosure controls. Any failure to maintain effective internal control over financial reporting and disclosure controls could harm our operating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we are implementing our internal control structure over the recently acquired business.

Given the difficulties inherent in the design and operation of internal control over financial reporting, as well as future growth of our businesses, we can provide no assurance as to either our or our independent registered public accounting firm’s conclusions about the effectiveness of internal controls in the future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the market price of our common units.

An impairment of goodwill and long-lived assets could reduce our earnings.

At March 31, 2019, we had goodwill and long-lived assets of $3.9 billion. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statements would result in a charge to our income, which would reduce our earnings.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

Our credit management procedures may not fully eliminate the risk of nonpayment by our customers. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or

wholly), requiring product deliveries over defined time periods, and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debt write-offs in the future may not be significant and any such nonpayment problems could impact our consolidated results of operations and potentially limit our ability to make payments on our debt obligations or distributions to our unitholders.

Our terminaling operations depend on various forms of transportation for receipt and delivery of crude oil, natural gas liquids and refined products.

We own natural gas liquids, crude oil and refined products terminals and lease refined products terminals. The facilities depend on pipelines, railroads, truck transports, and storage systems that are owned and operated by third parties. Any interruption of service on pipeline, railroad or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities impact the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

Our marketing operations depend on the availability of transportation and storage capacity.

Our product supply is transported and stored in facilities owned and operated by third parties. Any interruption of service on the pipeline or storage companies or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport products and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation affects the profitability of our operations.

The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year, which may require us to borrow money to make distributions to our unitholders during these quarters.

The natural gas liquids inventory we have presold to customers is highest during summer months, and our cash receipts are lowest during summer months. As a result, our cash available for distribution for the summer is much lower than for the winter. With lower cash flow during the first and second fiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our unitholders.

A significant increase in fuel prices may adversely affect our transportation costs.

Fuel is a significant operating expense for us in connection with the delivery of products to our customers. A significant increase in fuel prices will result in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

Some of our operations cross the United States/Canada border and are subject to cross-border regulation.

Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and United States customs and tax issues, and toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products.

An act of terror in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil and natural gas, which could have a material impact on both availability and price. Terrorist attacks in the areas of our operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our consolidated results of operations.


We depend on the leadership and involvement of key personnel for the success of our businesses.

We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our common units.

Risks InherentRelated to Our Partnership Structure and in an Investment in Us

Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty.duty.

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act (“Delaware LP Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the Partnership;
provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests of the Partnership;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and
provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties to our unitholders, and they may favor their own interests to the detriment of us and our unitholders.

The NGL Energy GP Investor Group owns and controls our general partner and its 0.1% general partner interest in us. Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders (see “–Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty,” above). The risk to our unitholders due to such conflicts may arise because of the following factors, among others:


our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group, in resolving conflicts of interest;
neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us;
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner;
our general partner determines which costs incurred by it are reimbursable by us;
our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus.
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This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights (“IDRs”);
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;
our general partner controls the enforcement of the obligations that it and its affiliates owe to us;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

In addition, certain members of the NGL Energy GP Investor Group and their affiliates currently hold interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, members of the NGL Energy GP Investor Group are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.


Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of management.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

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Our general partner interest or the control of our general partner may be transferred to a third party without the consent of our unitholders.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of the NGL Energy GP Investor Group to transfer all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

The IDRs of our general partner may be transferred to a third party.

Prior to the first day of the first quarter beginning after the 10th anniversary of the closing date of our initial public offering (“IPO”), a transfer of IDRs by our general partner requires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excluding common units held by our general partner and its affiliates). However, after the expiration of this period, ourOur general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its IDRs.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or may receive a negative return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.

Cost reimbursements to our general partner may be substantial and could reduce our cash available to make quarterly distributions to our unitholders.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These

expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates, will reduce the amount of cash available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, as well as reserves we have established to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or the agreements governing our indebtedness on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

We may issue additional units without the approval of our unitholders, which would dilute the interests of existing unitholders.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. Our issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

our existing unitholders’ proportionate ownership interest in us will decrease;
the amount of available cash for distribution on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.

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Our general partner, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its general partner interest in connection with a resetting of the target distribution levels related to its IDRs. This could result in lower distributions to our unitholders.

Our general partner has the right to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internalorganic growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner interests to our general partner in connection with resetting the target distribution levels.


Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our Partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

we were conducting business in a state but had not complied with that particular state’s partnership statute; or
a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware LP Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interests nor liabilities that are nonrecourse to the partnership are counted for purposes of determining whether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability.

The Preferred Units give the holders thereof liquidation and distribution preferences over our common unitholders.

In June 2017 we issued 8,400,000 Class BWe currently have three series of Preferred Units and in April 2019 we issued 1,800,000 Class C Preferred Units, whichoutstanding. All of these units rank senior to the common units with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, as long as any Preferred Units remain outstanding, we may not declare any distribution on our common units unless all accumulated and unpaid distributions have been declared and paid on the Preferred Units. In the event of our liquidation, winding-up or dissolution, the holders of the Preferred Units would have the right to receive proceeds from any such transaction before the holders of the common units. The payment of the liquidation preference could result in common unitholders not receiving any consideration if we were to
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liquidate, dissolve or wind up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common units, make it harder for us to sell common units in offerings in the future, or prevent or delay a change of control.

The issuance of common units upon exercise of certain warrants would cause dilution to existing common unitholders and may place downward pressure on the trading price of our common units.

We currently have outstanding exercisable warrants to purchase 25,500,000 common units at exercise prices ranging from $13.56 per unit to $17.45 per unit. Any exercise of these warrants would cause dilution to existing common unitholders and may place downward pressure on the trading price of our common units. The warrants may be exercised from and after the first anniversary of the date of issuance. Unexercised warrants will expire on the tenth anniversary of the date of issuance. The warrants will not participate in cash distributions.

Tax Risks to CommonOur Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. We could lose our status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation for federal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage and marketing of natural gas, natural gas products, and crude oil or other passive types of income such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income

that otherwise constitutes qualifying income. Although we do not believe, based upon our current operations, that we are treated as a corporation, we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income, there is a change in our business or there is a change in current law.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21% (changed from 35% under the recently enacted tax reform law), and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the market value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our business during our taxable year. However, under the Tax Cuts and Jobs Act of 2017 (the “Act”) signed into law by the President of the United States on December 22, 2017, beginning in tax year 2018, the deductibility of net interest expense is limited to 30% of our adjusted taxable income. For tax years beginning after December 31, 2017 and before January 1, 2022, the Act calculates adjusted taxable income using an EBITDA-based calculation. For tax years beginning January 1, 2022 and thereafter, the calculation of adjusted taxable income will not add back depreciation or amortization. Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level.
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These limitations might cause interest expense to be deducted by our unitholders in a later period than recognized in the GAAP financial statements.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships, including as a result of any fundamental tax reform.

We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification to the income tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.


Changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders could be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders could be substantially reduced.

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Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, our unitholders may be allocated taxable income and gain resulting from the sale and may not receive a common unit distribution. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any common unit distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.

In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.

In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our assets.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sellsells units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax exempt entities, such as employee benefit plans, individual retirement accounts (“IRAs”), Keogh plans and other retirement plans and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-United States person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the market value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This

disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our
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unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the market value of our common units or result in audit adjustments to tax returns of unitholders.

We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate level income taxes.

We conduct a portion of our operations through subsidiaries that are corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that our corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We prorate our items of income, gain, loss and deduction for United States federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S.United States Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize a gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize a gain or loss from the disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.


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There are limits on the deductibility of our losses that may adversely affect our unitholders.

There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units.

Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, holders of our common units are subject to other taxes, including foreign, state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own or control property now or in the future. Holders of our common units are required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in a number of states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax.

Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Preferred Units than the holders of our common units and such distributions will likely not be eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Preferred Units as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. A holder of our Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution. Otherwise, the holders of Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Preferred Units. If the Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Units.

Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, recently issued Treasury Regulations, which are effective for our taxable years beginning on or after January 1, 2020, provide that a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified publicly traded partnership income. As a result, income attributable to a guaranteed payment for the use of capital recognized by holders of Preferred Units is not eligible for the 20% deduction for qualified publicly traded partnership income. All holders of our Preferred Units are urged to consult a tax advisor to determine whether they are eligible to receive the 20% deduction for qualified publicly traded partnership income with respect to their Preferred Units.

A holder of Preferred Units will be required to recognize gain or loss on a sale of Preferred Units equal to the difference between the amount realized by such holder and such holder’s tax basis in the Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of Preferred Units to acquire such Preferred Unit. Gain or loss recognized by a holder of Preferred Units on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. Distributions to non-U.S. holders of Preferred Units will be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units
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may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Preferred Units.

All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units.

General Risks

The default by significant customers and counterparties or loss of one or more significant customers could materially or adversely affect our business, financial condition, results of operations and cash flows.

The deterioration in the financial condition of one or more of our significant customers or counterparties could result in their failure to perform under the terms of their agreement with us or default in the payment owed to us. Our customers and counterparties include industrial customers, local distribution companies, crude oil and natural gas producers, financial institutions and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. While we manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly) or other surety, requiring product deliveries over defined time periods, and credit monitoring, we are unable to completely eliminate the performance and credit risk to us associated with doing business with these parties. In a low commodity price environment, certain of our customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our contracts. The deterioration in the creditworthiness of our customers and the resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivables or tangible and intangible assets. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could materially or adversely affect our business, financial condition, results of operations, and cash flows. We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material and adverse effect on our consolidated results of operations. Additionally, certain key customers of the Grand Mesa Pipeline contribute significantly to the cash flows and profitability of that asset. Any loss of those customers or their contracts could have an adverse impact on our financial results. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code or, if we so agree, may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. The resolution of our outstanding claims against such a customer or counterparty is dependent on the terms of the plan of reorganization but may include our claims being converted to equity in the reorganized entity and in addition to impacting our business, financial condition and results of operations could require us to incur impairment charges against the associated assets or the write down of our goodwill.

The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

We encounter risk of counterparty nonperformance in our businesses. Disruptions in the supply of product and in the crude oil and natural gas liquidscommodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased gross margins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders.

If we fail to maintain an effective system of internal control, including internal control over financial reporting, we may be unable to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. We are also subject to the obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 (the “Sarbanes-Oxley Act”) to annually review and report on our internal control over financial reporting, and to the obligation under Section 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of our internal control over financial reporting.
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The Sarbanes-Oxley Act requires public companies to have and maintain effective disclosure controls and procedures to ensure timely disclosures of material information and to have management review the effectiveness of those controls on a quarterly basis. The Sarbanes-Oxley Act also requires public companies to have and maintain effective internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements and to have management review the effectiveness of those controls on an annual basis (and have the company’s independent auditors attest to the effectiveness of such internal controls).

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective internal control over financial reporting, including our disclosure controls. Any failure to maintain effective internal control over financial reporting and disclosure controls could harm our operating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we are implementing our internal control structure over the recently acquired business.

Given the difficulties inherent in the design and operation of internal control over financial reporting, as well as future growth of our businesses, we can provide no assurance as to either our or our independent registered public accounting firm’s conclusions about the effectiveness of internal controls in the future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the market price of our common units.

The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products.

An act of terror, or political unrest, in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil and natural gas, which could have a material impact on both availability and price. Since Russia’s military invasion of Ukraine in late February 2022, prices for commodities produced in those countries, including crude oil and natural gas, have risen sharply and have been volatile due to market concerns of worldwide supply constraints. Terrorist attacks in the areas of our operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our consolidated results of operations.

Product liability claims and litigation could adversely affect our business and results of operations.

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible liquids. As a result, we are subject to product liability claims and litigation, including potential class actions, in the ordinary course of business. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought against us might not be covered by our insurance policies. In addition, we have self-insured retention amounts which we would have to pay in full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to pay the amount of any settlement or judgment that is in excess of our policy limits. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely affect our business, consolidated results of operations, financial position and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial or operational systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our systems. In addition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to increase efficiency in our business. We use various systems in our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber security attacks on our customer and employee data may result in a financial loss,
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including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, resulting in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties

We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-compete agreements entered into in connection with acquisitions and other encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligationobligations under the revolving credit facility isABL Facility and indenture for the 2026 Senior Secured Notes are secured by liens and mortgages on substantially all of our real and personal property.

Other than as described below, weWe believe that we have all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operations of our business.

One of our facilities is operating with all but one of the required permits, as the state of Wyoming has not yet developed a process for issuing permits of this type. We believe that the permit will ultimately be granted, but we are unable to determine the timing of any action by the state of Wyoming.

Our corporate headquarters are in Tulsa, Oklahoma and are leased. We also lease corporate offices in Denver, Colorado and Houston, Texas.

For additional information regarding our properties and the reportable segments in which they are used, see Part I, Item 1–“Business.”

Item 3.    Legal Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the captions “Legal Contingencies” and “Environmental Matters” in Note 8 and “Third-party Bankruptcy” in Note 917 to our consolidated financial statements included in this Annual Report, which is incorporated by reference into this Item 3.


Item 4.    Mine Safety Disclosures

Not applicable.


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Table of Contents

PART II

Item 5.Item 5.    Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities


Market Information

Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.” At May 28, 2019,June 1, 2022, there were approximately 130100 common unitholders of record which does not include unitholders for whom common units may be held in “street name.”

Cash Distribution Policy

Available Cash

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

General Partner Interest

Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. 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’s interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. As of March 31, 2022, we owned 8.69% of our general partner.

Incentive Distribution Rights

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

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

    Marginal Percentage Interest In
Distributions
  Total Quarterly
Distribution Per Unit
 Limited Partner Unitholders 
General 
Partner (1)
Minimum quarterly distribution       $0.337500
 99.9% 0.1%
First target distribution above $0.337500
 up to $0.388125
 99.9% 0.1%
Second target distribution above $0.388125
 up to $0.421875
 86.9% 13.1%
Third target distribution above $0.421875
 up to $0.506250
 76.9% 23.1%
Thereafter above $0.506250
     51.9% 48.1%
Marginal Percentage Interest In Distributions
Total Quarterly Distribution Per UnitLimited Partner UnitholdersGeneral 
Partner (1)
Minimum quarterly distribution$0.337500 99.9 %0.1 %
First target distributionabove$0.337500 up to$0.388125 99.9 %0.1 %
Second target distributionabove$0.388125 up to$0.421875 86.9 %13.1 %
Third target distributionabove$0.421875 up to$0.506250 76.9 %23.1 %
Thereafterabove$0.506250 51.9 %48.1 %
(1)The maximum distribution of 48.1% does not include distributions that our general partner may receive on common units that it owns.
(1)    The maximum distribution of 48.1% does not include distributions that our general partner may receive on common units that it owns.
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Restrictions on the Payment of Distributions

As described in Note 87 to our consolidated financial statements included in this Annual Report, the Credit Agreement contains covenants limitingindenture to the 2026 Senior Secured Notes restricts us from paying distributions until our ability to pay distributions if we are in default under the Credit Agreement and to pay distributions that are in excess of available cashtotal leverage ratio (as defined in the Credit Agreement).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. In addition, quarterly distributions on the preferred unitsPreferred Units must be fully paid for all preceding fiscal quarters before we are permitted to declare or pay any distributions on our common units.

Sales As the distributions for all of Unregistered Securities

On Aprilour Preferred Units are cumulative, we are unable to declare a distribution for our common units unless all accumulated and unpaid distributions have been declared and paid on the Preferred Units. See Note 9 2019, we issued $450.0 million of 7.50% Senior Unsecured Notes Due 2026 (the “2026 Notes”) in a private placement. The 2026 Notes bear interest, which is payable on April 15 and October 15 of each year, beginning on October 15, 2019. The 2026 Notes mature on April 15, 2026. See Note 8 to our consolidated financial statements included in this Annual Report for a further discussion.discussion of the cumulative distributions for the Preferred Units.

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, as discussed further above. This resulted in the suspension of the quarterly common unit distributions, which began with the quarter ended December 31, 2020, and all preferred unit distributions, which began with the quarter ending March 31, 2021.

Common Unit Repurchase Program

The following table sets forth certain information with respect to repurchasessummarizes the repurchase of common units during the three months ended March 31, 2019:2022:
PeriodTotal Number of
Common Units
Purchased
Average Price
Paid Per
Common Unit
January 1-31, 2022— $— 
February 1-28, 202235,868 $2.00 
March 1-31, 2022— $— 
35,868 
Period Total Number of
Common Units
Purchased
 Average Price
Paid Per
Common Unit
 Total Number of
Common Units
Purchased as Part
of Publicly Announced
Program
 Approximate Dollar Value
of Common Units
that May Yet Be Purchased
Under the Program
January 1-31, 2019 
 $
 
 $
February 1-28, 2019 11,443
 $11.82
 
 $
March 1-31, 2019 
 $
 
 $
  11,443
   
 $

The common units were surrendered by employees to pay tax withholdingswithholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be “repurchases.” These repurchases were not part of a publicly announced program to repurchase our common units, nor do we currently have a publicly announced program to repurchase our common units.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the completion of our IPO,initial public offering, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan. See Part III, Item 12–“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder MattersMatters–Securities Authorized for Issuance Under Equity Compensation Plan,,” which is incorporated by reference into this Item 5.



Item 6.    Selected Financial Data[Reserved]

The following table summarizes selected consolidated historical financial data for the periods and as of the dates indicated. The following table should be read in conjunction with Part I, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.

The selected consolidated historical financial data at March 31, 2019 and 2018, and for each of the three years in the period ended March 31, 2019 is derived from our audited historical consolidated financial statements included in this Annual Report. The selected consolidated historical financial data at March 31, 2017, 2016 and 2015 and for each of the two years in the period ended March 31, 2016 is derived from our audited historical consolidated financial statements not included in this Annual Report.
  Year Ended March 31,
  2019 2018 2017 2016 2015
  (in thousands, except per unit data)
Income Statement Data          
Total revenues $24,016,907
 $16,907,296
 $12,707,203
 $11,468,646
 $16,312,860
Total cost of sales $23,284,917
 $16,412,641
 $12,228,404
 $10,761,793
 $15,679,669
Operating income (loss) $141,989
 $(17,174) $205,925
 $(148,699) $43,345
Interest expense $164,726
 $199,148
 $149,994
 $132,749
 $109,873
Loss (gain) on early extinguishment of liabilities, net $12,340
 $23,201
 $(24,727) $(28,532) $
(Loss) income from continuing operations $(63,724) $(226,385) $94,802
 $(231,318) $(15,229)
Net (loss) income from continuing operations allocated to common unitholders $(155,437) $(286,521) $57,645
 $(290,725) $(69,836)
Basic (loss) income from continuing operations per common unit $(1.26) $(2.37) $0.53
 $(2.77) $(0.81)
Diluted (loss) income from continuing operations per common unit $(1.26) $(2.37) $0.52
 $(2.77) $(0.81)
Cash Flows Data    
  
  
  
Net cash provided by (used in) operating activities $337,250
 $137,967
 $(25,038) $354,264
 $262,831
Net cash provided by (used in) investing activities $453,473
 $270,582
 $(363,126) $(445,327) $(1,366,221)
Net cash (used in) provided by financing activities $(794,245) $(394,281) $371,454
 $80,705
 $1,134,693
Cash distributions paid per common unit $1.56
 $1.56
 $1.56
 $2.54
 $2.37
Balance Sheet Data - Period End          
Total assets $5,902,493
 $6,151,122
 $6,320,379
 $5,560,155
 $6,655,792
Total long-term obligations, net of debt issuance costs and current maturities $2,223,708
 $2,853,254
 $3,143,030
 $3,155,062
 $2,838,052
Total equity $2,277,818
 $2,086,095
 $2,166,802
 $1,694,065
 $2,693,432

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a Delaware limited partnership (“we,” “us,” “our,” or the “Partnership”) formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At March 31, 2019,

Over the past three years, we made a number of important strategic actions in an effort to leverage the Partnership’s core areas of competitive strength and focus on generating stable, growing and predictable cash flows, while improving our operations included:

Crude Oil Logistics
Water Solutions
Liquids
Refined Products and Renewables

credit profile. These steps included the sale of the following:
On March 30, 2018, we sold a portion
Certain refined products businesses including TransMontaigne Product Services, LLC (“TPSL”), our refined products business in the mid-continent region of the United States (“Mid-Con”) and our Retail Propane segment to DCC LPGgas blending business in the southeastern and eastern regions of the United States (“DCC”Gas Blending”) for net proceeds of $212.4 million in cash, and recorded a gain on disposal of $89.3 million during the year ended March 31, 2018. The Retail Propane businesses subject to this transaction consisted of our operations across the Mid-Continent2020; and Western portions of the United States. On July 10, 2018, we completed the sale of virtually all of our remaining Retail Propane segment to Superior Plus Corp.
Our interest in Sawtooth Caverns, LLC (“Superior”Sawtooth”) for total consideration of $889.8 million in cash, and recorded a gain on disposal of $408.9 million during the year ended March 31, 2019. We retained2022.
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In addition, in our 50% ownership interestWater Solutions segment we acquired strategic water infrastructure assets including Mesquite Disposals Unlimited, LLC (“Mesquite”) and the equity interests of Hillstone Environmental Partners, LLC (“Hillstone”) during the year ended March 31, 2020, while in Victory Propane, LLC (“Victory Propane”), whichour Liquids Logistics segment we subsequently sold on August 14, 2018 (see acquired an approximately 225-mile propane pipeline in Michigan (the “Ambassador Pipeline”) during the year ended March 31, 2021. For more information regarding our dispositions and acquisitions transactions and the impact to our operations, see Note 217 and Note 18 to our consolidated financial statements included in this Annual Report on Form 10-K (“Annual Report”)). These transactions represent a

The sale of TPSL, Mid-Con and Gas Blending represented strategic shiftshifts in our operations and will have a significant effect on our operations and financial results going forward. Accordingly, the results of operations and cash flows related to our former Retail Propane segment (including equity in earnings of Victory Propane)TPSL, Mid-Con and Gas Blending have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted in the consolidated statements of operations and consolidated statements of cash flows. In addition, the assets and liabilities related to our former Retail Propane segment have been classified as held for sale within ouryears ended March 31, 2018 consolidated balance sheet.2021 and 2020. See Note 1 and Note 1718 to our consolidated financial statements included in this Annual Report for a further discussion of the transaction.these transactions.


Recent Developments

Repurchases of Senior Unsecured Notes

During the three months ended March 31, 2022, we repurchased $23.8 million of the 7.5% Senior Unsecured Notes Due 2023 (“2023 Notes”).

Global Pandemic and Ukraine War

The COVID-19 pandemic, including the outbreak of several variants, has caused continued volatility in commodity prices due to, among other things, reduced industrial activity and travel demand, varying worldwide restrictions and the timing of closing and re-opening of economies throughout the last two years. The unprecedented restrictions on travel and economic activity during the early stages of the COVID-19 pandemic significantly reduced demand for refined products. The lingering impact of the COVID-19 pandemic continues to ripple through the United States economy, most notably in the form of rising inflation and supply chain issues. Additionally, the Russian invasion of Ukraine beginning in February 2022 and the ongoing war has caused additional volatility in commodity prices on worldwide supply constraints and has seemed to have only amplified inflation and supply chain constraints in the United States.

While we have seen continued recovery in commodity prices since the beginning of the pandemic, primarily due to economies re-opening over time and the reduction in oil and natural gas supply resulting from the war in Ukraine, there is still an element of volatility that we expect to continue due to the uncertainty of the COVID-19 pandemic and the war in Ukraine. This volatility could negatively impact commodity prices or rising inflation could impact demand for refined products. 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.

Seismic Activity

The subsurface injection of produced water for disposal has been associated with recent induced seismic events in Texas and New Mexico. While these events have been relatively low magnitude, industry and relevant state regulators are, nevertheless, taking proactive measures to attempt to prevent similar induced seismic events. More specifically, we are engaged in various collaborative industry efforts with other disposal operators and relevant state regulatory agencies, working to collect and review data, enhance understanding of regional fault systems, and ultimately develop and implement appropriate longer-term mitigation strategies. As part of this effort, we have implemented reductions in injected volumes at certain facilities, and where appropriate have temporarily shut in facilities. To date, due to the capacity of our integrated system in affected areas, the diverse locations of our disposal facilities, and the connectivity of our system, we have not been negatively impacted by these actions.

Water Solutions

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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
52


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.

We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the Midland Basin in Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 656.2 million barrels of produced water across its areas of operation during the year ended March 31, 2022, we believe that we are the largest independent produced water transportation and disposal company in the United States.

The opportunity to generate revenue in our Water Solutions business is driven in large part by the level of crude oil production in the areas where our facilities are located. Prior to the pandemic, we saw the level of crude oil production increase, particularly in the Permian and DJ Basins, due to increasing or stable crude oil prices, which positively impacted our disposal volumes. Lower crude oil prices provide producers with less incentive to drill and complete new wells, which results in lower production and negatively impacts our disposal volumes.

Our Water Solutions segment generated operating income of $94.9 million during the year ended March 31, 2022. Our Water Solutions segment generated an operating loss of $92.7 million during the year ended March 31, 2021, which included an impairment charge of $84.3 million to write down the value of an asset group due to a decline in producer activity, resulting in lower disposal volumes, and to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report).

Crude Oil Logistics

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 trucking, marine and pipeline 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 owned and leased pipelines.

Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma.Oklahoma, St. James, Louisiana, and Magellan East Houston. We attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts whenever possible. When back-to-back physical contracts are not optimal, we enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts. We use our transportation assets to move crude oil from the wellhead to the highest value market. Spreads between crude oil prices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets.

The following table summarizes the range of low and high crude oil spot prices per barrel of NYMEXNew York Mercantile Exchange (“NYMEX”) West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end:
Crude Oil Spot Price Per Barrel
Year Ended March 31,LowHighAt Period End
2022$58.65 $123.70 $100.28 
2021 (1)$(37.63)$66.09 $59.16 
2020$20.09 $66.30 $20.48 
  Crude Oil Spot Price Per Barrel
Year Ended March 31, Low High At Period End
2019 $42.53
 $76.41
 $60.14
2018 $42.53
 $66.14
 $64.94
2017 $35.70
 $54.45
 $50.60
(1)     On April 20, 2020, crude oil prices collapsed due to low demand as a result of the COVID-19 lockdowns, the price war between Russia and Saudi Arabia and a lack of available storage.

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

Our Crude Oil Logistics segment generated operating income of $45.0 million during the year ended March 31, 2022. Our Crude Oil Logistics segment generated an operating loss of $7.4$304.3 million during the year ended March 31, 2019,2021, which included a lossimpairment charges of $105.0$383.6 million on our transaction with a third party in which they agreedrelated to be fully responsible for our future minimum volume commitment in exchange for $67.7 million of deficiency credits on a contract with a crude oil

pipeline operator and $35.3 million in cashthe Extraction Oil & Gas, Inc. (“Extraction”) bankruptcy (see Note 1317 to our consolidated financial statements included in this Annual Report for a further discussion)Report). Our Crude Oil Logistics segment generated operating income of $122.9 million during the year ended March 31, 2018, which included a gain of $108.6 million on the sale of our previously held 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”).


53


Water Solutions

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

Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our Water Solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling and producing new wells. The primary customer of our Wyoming facility has committed to deliver a specified minimum volume of water to our facility under a long-term contract. The primary customers of our Colorado facilities have committed to deliver all wastewater produced at wells within the DJ Basin to our facilities. Most customers of our other facilities are not under volume commitments, although many of our facilities have acreage dedications or are connected to producer facilities by pipeline.

Liquids Logistics
Our Water Solutions segment generated operating income of $210.5 million during the year ended March 31, 2019, which included a gain of $141.3 million on the sales of our Bakken water disposal business and our South Pecos water disposal business (see
Note 16 to our consolidated financial statements included in this Annual Report for a further discussion of both transactions). Our Water Solutions segment generated an operating loss of $24.2 million during the year ended March 31, 2018.

Liquids

Our Liquids Logistics segment purchases propane, butane,conducts supply operations for natural gas liquids, refined petroleum products and other products from refiners, processing plants, producers,biodiesel to a broad range of commercial, retail and other parties, and sells the products to retailers, wholesalers, refiners, and petrochemical plants throughoutindustrial customers across the United States and in Canada. Our Liquids segment owns 27These operations are conducted through our 24 owned terminals, throughout the United Statesthird-party storage and a salt dome storage facility joint venture in Utah, operatesterminal facilities, nine common carrier pipelines and a fleet of leased railcars,railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and leases underground storage capacity.expect to commence operations on our propane pipeline in Michigan in June 2022. We attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

Our wholesale Liquidsliquids business is a “cost-plus” business that can be affected by both price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage, and capital costs plus an acceptablea margin. Also, we conduct just-in-time sales for gasoline and diesel at a national network of terminals owned by third parties via rack spot sales that do not involve continuing contractual obligations to purchase or deliver product.

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

The following table summarizes the range of low and high propane spot prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of our main pricing hubs, for the periods indicated and the prices at period end:
Conway, KansasMt. Belvieu, Texas
Propane Spot Price Per GallonPropane Spot Price Per Gallon
Year Ended March 31,LowHighAt Period EndLowHighAt Period End
2022$0.67 $1.64 $1.37 $0.72 $1.63 $1.39 
2021$0.23 $1.53 $0.86 $0.25 $1.07 $0.92 
2020$0.18 $0.60 $0.25 $0.19 $0.68 $0.28 
  Conway, Kansas Mt. Belvieu, Texas
  Propane Spot Price Per Gallon Propane Spot Price Per Gallon
Year Ended March 31, Low High At Period End Low High At Period End
2019 $0.50
 $0.88
 $0.55
 $0.58
 $1.11
 $0.64
2018 $0.53
 $0.98
 $0.66
 $0.57
 $1.02
 $0.80
2017 $0.35
 $0.89
 $0.56
 $0.42
 $0.93
 $0.61

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Table of Contents


The following table summarizes the range of low and high butane spot prices per gallon at Mt. Belvieu, Texas for the periods indicated and the prices at period end:
  Butane Spot Price Per Gallon
Year Ended March 31, Low High At Period End
2019 $0.71
 $1.51
 $0.75
2018 $0.64
 $1.12
 $0.78
2017 $0.52
 $1.42
 $0.75

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

Butane Spot Price Per Gallon
Year Ended March 31,LowHighAt Period End
2022$0.78 $2.01 $1.71 
2021$0.28 $1.16 $0.98 
2020$0.19 $0.80 $0.29 
Our Liquids segment generated an operating loss of $2.9 million during the year ended March 31, 2019, which included a goodwill impairment charge of $66.2 million related to our salt dome storage facility joint venture in Utah (see
Note 6 to our consolidated financial statements included in this Annual Report). Our Liquids segment generated an operating loss of $93.1 million during the year ended March 31, 2018, which included a goodwill impairment charge of $116.9 million related to our salt dome storage facility joint venture in Utah (see Note 6 to our consolidated financial statements included in this Annual Report).

Refined Products and Renewables

Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country. In addition, in certain storage locations, our Refined Products and Renewables segment may also purchase unfinished gasoline blending components for subsequent blending into finished gasoline to supply our marketing business as well as third parties. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at terminals owned by third parties.

The following table summarizes the range of low and high Gulf Coast gasoline spot prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end:
Gasoline Spot Price Per Gallon
Year Ended March 31,LowHighAt Period End
2022$81.95 $154.67 $133.96 
2021$21.43 $90.30 $82.04 
2020$17.30 $89.55 $24.07 
  Gasoline Spot Price Per Barrel
Year Ended March 31, Low High At Period End
2019 $52.45
 $95.35
 $79.62
2018 $59.24
 $89.88
 $84.75
2017 $53.44
 $71.40
 $71.40

The following table summarizes the range of low and high diesel spot prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end:
Diesel Spot Price Per Gallon
Year Ended March 31,LowHighAt Period End
2022$74.44 $186.37 $155.03 
2021$25.64 $82.64 $74.39 
2020$40.08 $89.17 $42.51 

54



  Diesel Spot Price Per Barrel
Year Ended March 31, Low High At Period End
2019 $69.81
 $102.36
 $82.88
2018 $57.32
 $89.71
 $85.19
2017 $45.13
 $71.58
 $66.09
We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Our Refined ProductsLiquids Logistics segment generated an operating loss of $8.4 million during the year ended March 31, 2022, which included a net loss of $60.1 million related to the sale of Sawtooth (see Note 17 to our consolidated financial statements included in this Annual Report) and Renewablesa net loss of $11.8 million related to the sale of another terminal. Our Liquids Logistics segment generated operating income of $27.5 million and $56.7$70.4 million during the yearsyear ended March 31, 2019 and 2018, respectively.2021.


Consolidated Results of Operations

The following table summarizes our consolidated statements of operations for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Revenues$7,947,915 $5,227,023 $7,584,000 
Cost of sales7,139,312 4,493,822 6,604,383 
Operating expenses285,535 254,562 332,993 
General and administrative expense63,546 70,468 113,664 
Depreciation and amortization288,720 317,227 265,312 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Revaluation of liabilities(6,495)6,261 9,194 
Operating income (loss)83,043 (390,753)(3,332)
Equity in earnings of unconsolidated entities1,400 1,938 1,291 
Interest expense(271,640)(198,799)(181,184)
Gain (loss) on early extinguishment of liabilities, net1,813 (16,692)1,341 
Other income (expense), net2,254 (36,503)1,684 
Loss from continuing operations before income taxes(183,130)(640,809)(180,200)
Income tax (expense) benefit(971)3,391 (345)
Loss from continuing operations(184,101)(637,418)(180,545)
Loss from discontinued operations, net of tax— (1,769)(218,235)
Net loss(184,101)(639,187)(398,780)
Less: Net (income) loss attributable to noncontrolling interests(655)(632)1,773 
Net loss attributable to NGL Energy Partners LP$(184,756)$(639,819)$(397,007)
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Total revenues $24,016,907
 $16,907,296
 $12,707,203
Total cost of sales 23,284,917
 16,412,641
 12,228,404
Operating expenses 240,684
 201,068
 189,003
General and administrative expense 107,534
 98,129
 105,805
Depreciation and amortization 212,860
 209,020
 180,239
Loss (gain) on disposal or impairment of assets, net 34,296
 (17,104) (208,890)
Revaluation of liabilities (5,373) 20,716
 6,717
Operating income (loss) 141,989
 (17,174) 205,925
Equity in earnings of unconsolidated entities 2,533
 7,539
 3,830
Revaluation of investments 
 
 (14,365)
Interest expense (164,726) (199,148) (149,994)
(Loss) gain on early extinguishment of liabilities, net (12,340) (23,201) 24,727
Other (expense) income, net (29,946) 6,953
 26,612
(Loss) income from continuing operations before income taxes (62,490) (225,031) 96,735
Income tax expense (1,234) (1,354) (1,933)
(Loss) income from continuing operations (63,724) (226,385) 94,802
Income from discontinued operations, net of tax 403,119
 156,780
 49,072
Net income (loss) 339,395
 (69,605) 143,874
Less: Net loss (income) attributable to noncontrolling interests 20,206
 (240) (6,832)
Less: Net loss (income) attributable to redeemable noncontrolling interests 446
 (1,030) 
Net income (loss) attributable to NGL Energy Partners LP $360,047
 $(70,875) $137,042

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented due to business combinations, disposalsacquisitions, dispositions and other transactions.

Recent DevelopmentsAcquisitions and Dispositions

TransactionsWe completed several acquisitions and dispositions during the Three Months Ended March 31, 2019

Repurchase and Redemption of Senior Unsecured Notes

During the three monthsyears ended March 31, 2019,2022 and 2021. These transactions impact the comparability of our results of operations between our current and prior fiscal years.

On June 18, 2021, we repurchased $11.9 millionsold our approximately 71.5% interest in Sawtooth to a group of the 2019 Notes (as defined herein). See buyers (see Note 817 to our consolidated financial statements included in this Annual Report forReport).

In March 2021, we acquired the Ambassador Pipeline, an approximately 225-mile propane pipeline, which runs from the Kalkaska gas plant in Kalkaska County, Michigan to a further discussion.

Ontermination point near Marysville in St. Clair County, Michigan. During the year ended March 15, 2019,31, 2021, we paid $329.7 millionsold certain permits, land and a saltwater disposal facility to redeem all of our outstanding 2019 Notes. See a third-party (see Note 817 to our consolidated financial statements included in this Annual ReportReport).

Seasonality

Seasonality impacts our Liquids Logistics segment. Consequently, for a further discussion.our Liquids Logistics segment, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of our fiscal year. We generally

Credit Agreement

55
On February 6, 2019, we amended the Credit Agreement (as defined herein) to, among other things, reset and increase the basket for the repurchase of common units, decrease the maximum total leverage indebtedness ratio for future quarters and amend the defined term “Consolidated EBITDA.” See Note 8 to our consolidated financial statements included in this Annual Report for a further discussion.


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Table
borrow under the revolving credit facility to supplement our operating cash flows during the periods in which we are building inventory. See “–Liquidity, Sources of Contents
Capital and Capital Resource Activities–Cash Flows.”

Subsequent Events

See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of transactions that occurred subsequent to March 31, 2019.2022.


Acquisitions

As discussed below, we completed numerous acquisitions during the years ended March 31, 2019 and 2018. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

During the year ended March 31, 2019, in our Water Solutions segment, we acquired the remaining 18.375% interest in NGL Water Pipelines, LLC, six saltwater disposal facilities (including 22 saltwater disposal wells), two ranches and four freshwater facilities (including 45 freshwater wells). In our Liquids segment, we acquired the natural gas liquids terminal business of DCP Midstream, LP and in our Refined and Renewables segment, we acquired two refined products terminals. See Note 4 to our consolidated financial statements included in this Annual Report for a further discussion.

In our Retail Propane segment, we acquired three retail propane businesses and the remaining 40% interest in Atlantic Propane, LLC. The assets and liabilities of these retail propane transactions were included in the sale of virtually all of our remaining Retail Propane segment on July 10, 2018 and the operations have been classified as discontinued. See Note 4 and Note 17 to our consolidated financial statements included in this Annual Report for a further discussion.

During the year ended March 31, 2018, in our Water Solutions segment, we acquired the remaining 50% ownership interest in NGL Solids Solutions, LLC, and in our Retail Propane segment, we acquired seven retail propane businesses and certain assets from Victory Propane. The assets and liabilities of these retail propane businesses are included in current assets and current liabilities held for sale in our March 31, 2018 consolidated balance sheet and the operations have been classified as discontinued. See Note 13 and Note 17 to our consolidated financial statements included in this Annual Report for a further discussion.

Subsequent Events

See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of the acquisitions that occurred subsequent to March 31, 2019.

Dispositions

Sale of South Pecos Water Disposal Business

On February 28, 2019, we completed the sale of our South Pecos water disposal business to a subsidiary of WaterBridge Resources LLC for $232.2 million in net cash proceeds and recorded a gain on disposal of $107.9 million during the year ended March 31, 2019. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

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 Water Solutions segment have not been classified as discontinued operations.

Sale of Bakken Saltwater Disposal Business

On November 30, 2018, we completed the sale of NGL Water Solutions Bakken, LLC to an affiliate of Tallgrass Energy, LP for $85.0 million in net cash proceeds and recorded a gain on disposal of $33.4 million during the year ended March 31, 2019. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

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 Water Solutions segment have not been classified as discontinued operations.

Sale of Retail Propane Business

On March 30, 2018, we sold a portion of our Retail Propane segment to DCC. On July 10, 2018, we completed the sale of virtually all of our remaining Retail Propane segment to Superior and on August 14, 2018, we sold our previously held interest in Victory Propane. See “Overview” above for a further discussion.

Sawtooth Joint Venture

On March 30, 2018, we completed the transaction to form a joint venture with Magnum Liquids, LLC, a portfolio company of Haddington Ventures LLC, along with Magnum Development, LLC and other Haddington-sponsored investment entities (collectively “Magnum”) to focus on the storage of natural gas liquids and refined products by combining our Sawtooth salt dome storage facility with Magnum’s refined products rights and adjacent leasehold.Magnum acquired an approximately 28.5% interest in Sawtooth from us, in exchange for consideration consisting of a cash payment of approximately $37.6 million (excluding working capital) and the contribution of certain refined products rights and adjacent leasehold. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

Sale of Interest in Glass Mountain

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain for net proceeds of $292.1 million and recorded a gain on disposal of $108.6 million during the three months ended December 31, 2017. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

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 Crude Oil Logistics segment have not been classified as discontinued operations.

Trends

Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our Crude Oil Logistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the period from July 2014 through February 2016. Crude oil prices have rebounded and at March 31, 2019, the spot price for NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma was $60.14 per barrel. While crude oil production in the United States has been strong in recent years, a sharp decline in crude oil prices could reduce the incentive for producers to expand production. Low crude oil prices could result in declines in crude oil production and may adversely impact volumes and margins in our Crude Oil Logistics business. Crude oil price declines have had an adverse impact on many participants in the energy markets, and the inherent risk of customer or counterparty nonperformance is higher when crude oil prices are low or in decline.

From January 2015 to January 2018, crude oil markets were in contango, a condition in which forward crude oil prices are greater than spot prices. Our Crude Oil Logistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory and when we sell it. In addition, we are able to better utilize our storage assets when contango markets justify storing barrels. During the year ended March 31, 2019, crude oil markets have moved from being in backwardation to fairly flat. Backwardation is a condition in which forward crude oil prices are lower than spot prices. When markets are in backwardation, falling prices typically have an unfavorable impact on our margins.

Our opportunity to generate revenues in our Water Solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. As described above, crude oil prices declined sharply since July 2014 but have increased since March 31, 2016. Also, drilling rigs and production have increased since March 31, 2016, particularly in the Permian and DJ Basins which has positively impacted the volumes of our Water Solutions business (during the three months ended March 31, 2019 we processed 860,000 barrels of wastewater per day, compared to 761,000 barrels of wastewater per day during the three months ended March 31, 2018). A portion of the revenues in our Water Solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater. These recovered hydrocarbon revenues have increased due primarily to an increase in the volume of wastewater processed at existing facilities as well as facilities acquired from acquisitions and an increase in crude oil prices; however, these revenues were negatively impacted by a lower percentage of skim oil volumes recovered per wastewater barrel processed. This lower percentage was due primarily to an increase in wastewater transported through pipelines (which contains less oil per barrel of wastewater), as well as operational changes in the DJ Basin, which have resulted in lower per-barrel revenues for our Water Solutions business.

An important element of our Refined Products and Renewables segment relates to the marketing of refined products in the Southeast and East Coast regions. We purchase product in the Gulf Coast, transport the product on third party pipelines, and sell the product at terminals owned by third parties. Most of the contracts with these customers are one year in duration, with pricing indexed to prices in the Gulf Coast at the date of sale plus a specified differential. To operate this business we maintain inventory in transit on third party pipelines and at destination terminals where we sell the product. The value of this inventory

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Table of Contents

will increase or decrease as market prices change. In order to mitigate this risk, we enter into futures contracts, which are only available based on New York Harbor pricing. Because our contracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, the futures contracts are not a perfect hedge against our inventory holding risk. During any given period, spreads between prices in the Gulf Coast and New York Harbor could narrow or widen, which could reduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

During the year ended March 31, 2019, prices for refined products increased. Gulf Coast prices, on which our sales contracts are based, increased less than the New York Harbor prices, on which our futures contracts are based, which had an unfavorable impact on our cost of sales. Based on historical experience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during any individual quarter within the year, and that we should expect more volatility in cost of sales among quarters within a fiscal year than we would expect during a full fiscal year.

Seasonality

Seasonality impacts our Liquids and Refined Products and Renewables segments. Consequently, for our Liquids business, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of our fiscal year. The seasonal motor fuel blend during the third quarter of our fiscal year impacts the value of our gasoline inventory in our Refined Products and Renewables business and also represents a period when we build inventory into our system. We borrow under the Revolving Credit Facility to supplement our operating cash flows during the periods in which we are building inventory. See “–Liquidity, Sources of Capital and Capital Resource ActivitiesCash Flows.”


Segment Operating Results for the Years Ended March 31, 2019 2022 and 2018

2021
Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
  Year Ended March 31,  
  2019 2018 Change
  (in thousands, except per barrel amounts)
Revenues:      
Crude oil sales $3,011,355
 $2,151,203
 $860,152
Crude oil transportation and other 161,336
 122,786
 38,550
Total revenues (1) 3,172,691
 2,273,989
 898,702
Expenses:  
  
  
Cost of sales-excluding impact of derivatives 2,939,702
 2,120,640
 819,062
Cost of sales-derivative (gain) loss (1,085) 7,021
 (8,106)
Operating expenses 53,352
 47,846
 5,506
General and administrative expenses 6,512
 6,584
 (72)
Depreciation and amortization expense 74,165
 80,387
 (6,222)
Loss (gain) on disposal or impairment of assets, net 107,424
 (111,393) 218,817
Total expenses 3,180,070
 2,151,085
 1,028,985
Segment operating (loss) income $(7,379) $122,904
 $(130,283)
       
Crude oil sold (barrels) 48,366
 39,626
 8,740
Crude oil transported on owned pipelines (barrels) 42,564
 33,454
 9,110
Crude oil storage capacity - owned and leased (barrels) (2) 5,232
 6,159
 (927)
Crude oil storage capacity leased to third parties (barrels) (2) 2,564
 2,641
 (77)
Crude oil inventory (barrels) (2) 827
 1,219
 (392)
Crude oil sold ($/barrel) $62.262
 $54.288
 $7.974
Cost per crude oil sold ($/barrel) $60.758
 $53.694
 $7.064
Crude oil product margin ($/barrel) $1.504
 $0.594
 $0.910
(1)Revenues include $36.1 million and $13.9 million of intersegment sales during the years ended March 31, 2019 and 2018, respectively, that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2019 and March 31, 2018, respectively.

Crude Oil Sales Revenues.The increase was due primarily to an increase in crude oil prices and sales volumes during the year ended March 31, 2019, compared to the year ended March 31, 2018. The increase in crude oil prices throughout our fiscal year 2019 has led to an increase in production volumes for us to market. We continue to market crude oil volumes in the majority of the basins across the United States to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues.The increase was due to our Grand Mesa Pipeline, which increased revenues by $17.0 million during the year ended March 31, 2019, compared to the year ended March 31, 2018, primarily due to increased production growth in the DJ Basin. During the year ended March 31, 2019, approximately 42.6 million barrels of crude oil were transported on the Grand Mesa Pipeline, which averaged approximately 117,000 barrels per day, physically, and financial volumes averaged approximately 120,000 barrels per day (volume amounts are from both internal and external parties). In addition, during the year ended March 31, 2019, a new crude marketing contract increased revenues by $23.4 million. This was partially offset by a reduction in railcar sublease revenue.

Cost of Sales-Excluding Impact of Derivatives.The increase was due primarily to an increase in crude oil prices and sales volumes during the year ended March 31, 2019, compared to the year ended March 31, 2018.

Cost of Sales-Derivatives. Our cost of sales during the year ended March 31, 2019 included $0.6 million of net realized losses on derivatives and $1.7 million of net unrealized gains on derivatives. Our cost of sales during the year ended

March 31, 2018 included $4.2 million of net realized losses on derivatives and $2.8 million of net unrealized losses on derivatives.

Operating and General and Administrative Expenses.The increase was due primarily to utilities related to the higher volumes transported on the Grand Mesa Pipeline.

Depreciation and Amortization Expense.The decrease was due primarily to downsizing our fleet of crude transportation assets, which decreased depreciation and amortization expense by $4.3 million during the year ended March 31, 2019, compared to the year ended March 31, 2018. The decrease was also due to certain intangible assets being fully amortized in prior periods.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2019, we recorded a net loss of $107.4 million, which included a loss of $105.0 million on our transaction with a third party in which they agreed to be fully responsible for our future minimum volume commitment in exchange for $67.7 million of deficiency credits on a contract with a crude oil pipeline operator and $35.3 million in cash (see Note 2 and Note 13 to our consolidated financial statements included in this Annual Report). The loss also includes additional costs related to this transaction of $2.0 million. In addition, we recorded a loss of $1.3 million related to the sale of two terminals during the year ended March 31, 2019. During the year ended March 31, 2018, we recorded a gain of $108.6 million on the sale of our previously held 50% interest in Glass Mountain (see Note 16 to our consolidated financial statements included in this Annual Report). In addition, we recorded a net gain of $2.8 million on the sales of certain other assets.


Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:indicated.
Year Ended March 31,
20222021Change
(in thousands, except per barrel and per day amounts)
Revenues:
Water disposal service fees$397,128 $308,511 $88,617 
Sale of recovered crude oil77,203 28,599 48,604 
Recycled water11,343 3,015 8,328 
Other revenues59,192 30,861 28,331 
Total revenues544,866 370,986 173,880 
Expenses:
Cost of sales-excluding impact of derivatives26,340 2,557 23,783 
Derivative loss7,640 7,065 575 
Operating expenses175,022 142,371 32,651 
General and administrative expenses7,352 6,403 949 
Depreciation and amortization expense214,558 222,107 (7,549)
Loss on disposal or impairment of assets, net25,598 76,942 (51,344)
Revaluation of liabilities(6,495)6,261 (12,756)
Total expenses450,015 463,706 (13,691)
Segment operating income (loss)$94,851 $(92,720)$187,571 
Produced water processed (barrels per day)
Delaware Basin1,531,830 1,148,582 383,248 
Eagle Ford Basin99,298 78,397 20,901 
DJ Basin142,611 111,016 31,595 
Other Basins24,179 26,596 (2,417)
Total1,797,918 1,364,591 433,327 
Recycled water (barrels per day)93,487 43,503 49,984 
Total (barrels per day)1,891,405 1,408,094 483,311 
Skim oil sold (barrels per day)2,864 1,957 907 
Service fees for produced water processed ($/barrel) (1)$0.61 $0.62 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (1)$0.12 $0.06 $0.06 
Operating expenses for produced water processed ($/barrel) (1)$0.27 $0.29 $(0.02)
  Year Ended March 31,  
  2019 2018 Change
  (in thousands, except per barrel and per day amounts)
Revenues:      
Wastewater disposal service fees $189,947
 $149,114
 $40,833
Sale of recovered hydrocarbons 72,678
 58,948
 13,730
Other service revenues 39,061
 21,077
 17,984
Total revenues 301,686
 229,139
 72,547
Expenses:      
Cost of sales-excluding impact of derivatives 2,668
 2,150
 518
Cost of sales-derivative (gain) loss (13,455) 17,195
 (30,650)
Operating expenses 130,748
 105,200
 25,548
General and administrative expenses 6,615
 2,623
 3,992
Depreciation and amortization expense 108,162
 98,623
 9,539
(Gain) loss on disposal or impairment of assets, net (138,204) 6,863
 (145,067)
Revaluation of liabilities (5,373) 20,716
 (26,089)
Total expenses 91,161
 253,370
 (162,209)
Segment operating income (loss) $210,525
 $(24,231) $234,756
       
Wastewater processed (barrels per day)      
Permian Basin 461,456
 289,360
 172,096
Eagle Ford Basin 270,849
 235,713
 35,136
DJ Basin 161,010
 113,771
 47,239
Other Basins 53,799
 68,466
 (14,667)
Total 947,114
 707,310
 239,804
Solids processed (barrels per day) 6,957
 5,662
 1,295
Skim oil sold (barrels per day) 3,567
 3,210
 357
Service fees for wastewater processed ($/barrel) $0.55
 $0.58
 $(0.03)
Recovered hydrocarbons for wastewater processed ($/barrel) $0.21
 $0.23
 $(0.02)
Operating expenses for wastewater processed ($/barrel) $0.38
 $0.41
 $(0.03)

Wastewater(1)    Total producedwater barrels processed during the years ended March 31, 2022 and 2021 were 656,240,083 and 498,075,843, respectively.

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in the volumeproduced water volumes processed as a result of wastewater processed at existing facilities as well as facilities acquired from acquisitions. We continue to benefit from the increased crude oil production driven by higher crude oil prices and gas production and rig counts as compared to the prior yearcompletion activity, primarily in the basins in which we operate, particularly in the PermianDelaware Basin. This was partially offset by lower service fees received per barrel due to increased volumes from customers with long-term acreage dedications or minimum volume commitments with lower contracted fees.

Recovered HydrocarbonCrude 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 volumenumber of wastewater processed at existing facilities as well as facilities acquired from acquisitions and an increase wells completed
56



in crude oil prices; however, these revenues were negatively impacted by a lower percentageour area of operations during the period with increased flowback activity resulted in higher skim oil volumes recovered per wastewater barrel of produced water processed. This lower percentage

Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities. The increase was due primarily to increasing demand for water to be used in completions, driven by an increase in wastewater transported through pipelines (which contains less oil per barrel of wastewater), as well as operational changesdrilling and completion activity primarily in the DJ Basin.Delaware Basin, and our customers transition from brackish non-potable water to recycled water.

Other Service Revenues. Other service revenues primarily include solids disposalbrackish non-potable water revenues, water pipeline revenues, land surface use revenues and freshwatersolids disposal revenues. The increase was due primarily to higher sales of brackish non-potable water and pipeline revenues, alldriven 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 which increased during the year ended March 31, 2019caliche due to increased volumes as well as acquisitions.producer activity.

Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in expensescosts related to bring wastewaterthe transfer of brackish non-potable water and recycled water to certainthe purchaser as well as increased purchases of ourbrackish non-potable water solutions facilitiesfrom third-parties to meet customer needs.

Derivative Loss.


Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbonscrude oil we expect to recover when processing the wastewaterproduced water and selling therecovered skim oil. During the year ended March 31, 2022, we had $11.7 million of net unrealized losses on derivatives and $4.0 million of net realized gains on derivatives. During the year ended March 31, 2021, we had $24.5 million of net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. At March 31, 2022, we had approximately 3,000 barrels per day hedged for the next six months at an average price of $87.65 per barrel.

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. Going forward, the Partnership expects to see slight decreases in its operating expenses per barrel of produced water processed due to continued focus on cost maintenance and reductions 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 year ended March 31, 2022 as well as certain other long-term assets being fully amortized or impaired during the years ended March 31, 2021 and 2022. These decreases were partially offset by the depreciation of newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2022, we recorded a net loss of $29.8 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 year ended March 31, 2021, we recorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report);
an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
a net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $14.0 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17 to our consolidated financial statements included in this Annual Report).
57




Revaluation of Liabilities. During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment. During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$2,432,393 $1,574,699 $857,694 
Crude oil transportation and other84,171 153,588 (69,417)
Total revenues (1)2,516,564 1,728,287 788,277 
Expenses:   
Cost of sales-excluding impact of derivatives2,271,973 1,473,330 798,643 
Derivative loss92,027 49,314 42,713 
Operating expenses54,606 56,918 (2,312)
General and administrative expenses7,537 8,038 (501)
Depreciation and amortization expense48,489 60,874 (12,385)
(Gain) loss on disposal or impairment of assets, net(3,101)384,143 (387,244)
Total expenses2,471,531 2,032,617 438,914 
Segment operating income (loss)$45,033 $(304,330)$349,363 
Crude oil sold (barrels)31,091 38,349 (7,258)
Crude oil transported on owned pipelines (barrels)28,410 32,797 (4,387)
Crude oil storage capacity - owned and leased (barrels) (2)5,232 5,239 (7)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 1,501 — 
Crude oil inventory (barrels) (2)1,339 1,201 138 
Crude oil sold ($/barrel)$78.235 $41.062 $37.173 
Cost per crude oil sold ($/barrel) (3)$73.075 $38.419 $34.656 
Crude oil product margin ($/barrel) (3)$5.160 $2.643 $2.517 
(1)    Revenues include $11.1 million and $6.7 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, 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 year ended March 31, 2022, compared to the year ended March 31, 2021. This was offset by a reduction in sales volumes, primarily due to lower production in the DJ Basin. In addition, volumes also declined due to an increase in buy/sell transactions during the year ended March 31, 2022, compared to the year ended March 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 all 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 $72.6 million during the year ended March 31, 2022, compared to the year ended March 31, 2021. During the year ended March 31, 2022, physical volumes on the Grand Mesa Pipeline averaged approximately 78,000 barrels per day, compared to approximately 90,000 barrels per day for the year ended March 31, 2021 (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.

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Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in crude oil prices during the year ended March 31, 2022, compared to the year ended March 31, 2021. The increase was partially offset by a reduction in volumes, as discussed above in “Crude Oil Sales Revenues.”

Derivative Loss. Our cost of sales during the year ended March 31, 20192022 included $15.5$115.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $23.7 million of net unrealized gains on derivatives and $2.1 million ofderivatives. The amounts for the year ended March 31, 2022 includes net realized losses on derivatives. In December 2018, we settledof $83.5 million and unrealized gains of $45.0 million associated with derivative contracts that had scheduled settlement dates from January 2019 through December 2020instruments related to our hedge of the CMA Differential Roll, defined and recorded a gain of $8.4 million on those derivatives.discussed below under “Non-GAAP Financial Measures.” Our cost of sales during the year ended March 31, 20182021 included $13.7$25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivativesderivatives. Gains and $3.5 millionlosses from derivative activity should be offset by margin generated by the sale of net realized losses on derivatives.the physical product.

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 related to deficiency volumes from Extraction of $5.7 million during the year ended March 31, 2021. The decrease was offset by an increase in utility expenses due to Grand Mesa increased utility rates, as well as increased business insurance due to policy rate increases for the year ended March 31, 2022.

Depreciation and Amortization Expense. The decrease was due primarily to the increase in the numberreduction of water disposal facilities and wells that we own and operatedamortization expense due to higher volumes processedthe impairment of certain intangible assets at existing facilities and facilities acquired from acquisitions, partiallythe end of the prior year. This was offset by cost reduction efforts. Due to the higher volumes processed, our cost per barrel has decreased, as shown in the table above. Also contributing to the increase was an increase in acquisition expenses relateddepreciation expense due to onereducing the estimated useful lives of our ranch acquisitions.railcars.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions and developed facilities, partially offset by the disposition of our Bakken and South Pecos water disposal businesses and certain intangible assets being fully amortized during the years ended March 31, 2019 and 2018.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2019,2022, we completedrecorded a gain of $5.5 million on the sale of our South Pecos water disposal businesstrucking assets and a loss of $2.2 million due to damage caused by Hurricane Ida to one of our Gulf Coast terminals. During the year ended March 31, 2021, we recorded a gainnet loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report) and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report).

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Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)$1,899,898 $1,124,087 $775,811 
Cost of sales-excluding impact of derivatives1,876,728 1,108,493 768,235 
Derivative loss2,907 930 1,977 
Product margin20,263 14,664 5,599 
Propane sales:
Revenues (1)1,325,941 1,027,582 298,359 
Cost of sales-excluding impact of derivatives1,313,765 949,402 364,363 
Derivative (gain) loss(20,519)10,994 (31,513)
Product margin32,695 67,186 (34,491)
Butane sales:
Revenues (1)863,348 517,857 345,491 
Cost of sales-excluding impact of derivatives794,180 469,394 324,786 
Derivative loss18,690 22,353 (3,663)
Product margin50,478 26,110 24,368 
Other product sales:
Revenues-excluding impact of derivatives (1)791,125 446,744 344,381 
Cost of sales-excluding impact of derivatives748,392 424,191 324,201 
Derivative loss (gain)15,812 (7,078)22,890 
Product margin26,921 29,631 (2,710)
Service revenues:
Revenues (1)16,200 33,915 (17,715)
Cost of sales1,404 4,751 (3,347)
Product margin14,796 29,164 (14,368)
Expenses:
Operating expenses55,907 55,273 634 
General and administrative expenses7,166 8,507 (1,341)
Depreciation and amortization expense18,714 29,184 (10,470)
Loss on disposal or impairment of assets, net71,807 3,350 68,457 
Total expenses153,594 96,314 57,280 
Segment operating (loss) income$(8,441)$70,441 $(78,882)
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Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3)156,219 427,975 (271,756)
Refined products sold (gallons)776,797 834,717 (57,920)
Refined products sold ($/gallon)$2.446 $1.347 $1.099 
Cost per refined products sold ($/gallon) (4)$2.416 $1.328 $1.088 
Refined products product margin ($/gallon) (4)$0.030 $0.019 $0.011 
Refined products inventory (gallons) (2)1,090 1,223 (133)
Propane sold (gallons)1,034,706 1,364,224 (329,518)
Propane sold ($/gallon)$1.281 $0.753 $0.528 
Cost per propane sold ($/gallon) (4)$1.270 $0.696 $0.574 
Propane product margin ($/gallon) (4)$0.011 $0.057 $(0.046)
Propane inventory (gallons) (2)37,719 51,026 (13,307)
Propane storage capacity leased to third parties (gallons) (2)(3)— 53,947 (53,947)
Butane sold (gallons)588,032 655,256 (67,224)
Butane sold ($/gallon)$1.468 $0.790 $0.678 
Cost per butane sold ($/gallon) (4)$1.351 $0.716 $0.635 
Butane product margin ($/gallon) (4)$0.117 $0.074 $0.043 
Butane inventory (gallons) (2)19,825 20,066 (241)
Butane storage capacity leased to third parties (gallons) (2)(3)— 56,700 (56,700)
Other products sold (gallons)376,906 471,245 (94,339)
Other products sold ($/gallon)$2.099 $0.948 $1.151 
Cost per other products sold ($/gallon) (4)$1.986 $0.900 $1.086 
Other products product margin ($/gallon) (4)$0.113 $0.048 $0.065 
Other products inventory (gallons) (2)18,614 19,195 (581)
(1)    Revenues include $1.3 million and $6.1 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, respectively.
(3)    Decrease from March 31, 2021 relates to the sale of Sawtooth on disposalJune 18, 2021 (see Note 17 to our consolidated financial statements included in this Annual Report).    
(4)    Cost and product margin per gallon excludes the impact of $107.9derivatives.

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 prices. This was offset by a reduction in volumes sold due to tighter supply in the market. In certain markets in which we compete, allocation of product from suppliers was reduced due to lower demand as a result of the COVID-19 pandemic. We are continuing to work to increase those allocations as demand for refined products increases.

Refined Products Derivative Loss. Our refined products margin during the year ended March 31, 2022 included a realized loss of $2.9 million and the year ended March 31, 2021 included a realized loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions.

Refined Products product margins per gallon of refined products sold for the year ended March 31, 2022 increased from the year ended March 31, 2021 primarily due to supply being short during the three months ended December 31, 2021, as a result of extended refinery downtime in certain markets in which we compete, and being well positioned during the extreme volatility surrounding global events occurring in the three months ended March 31, 2022.

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 domestic 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
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demand due to warmer than normal autumn temperatures, which resulted in lower product demand for crop drying, unusually warm weather during the early winter months and reduced volumes due to the loss of two producer services agreements.

Propane Derivative (Gain) Loss. Our wholesale propane cost of sales included $2.0 millionof net unrealized gains on derivatives and $18.5 million of net realized gains on derivatives during the year ended March 31, 2022. During the year ended March 31, 2021, our cost of wholesale propane sales included $3.3 million of net unrealized gains on derivatives and $14.3 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 winter season, along with increased competition in a number of markets where NGL purchases and sells propane. Midwestern demand was down year-over-year due to lower product demand for crop drying and warmer fall and winter weather. Our margin was also impacted by lower product allocation from certain suppliers and lower storage utilization due to decreased demand and the backwardated market structure.

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 year ended March 31, 2022 included $1.0 millionof net unrealized gains on derivatives and $19.7 million of net realized losses on derivatives. Our cost of butane sales included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives during the year ended March 31, 2021.

Butane product margins per gallon of butane sold were higher during year ended March 31, 2022 than during the year ended March 31, 2021 due primarily to a tight supply market, driven by an increase in demand for exports and an 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 and increased demand for biodiesel. This was partially offset by reduced natural gasoline volumes during the year ended March 31, 2022 as more production was being shipped via pipelines, reducing the availability for product to be shipped by railcars.

Other Products Derivatives Loss (Gain). Our derivatives of other products included $15.8 million of net realized losses on derivatives and there are no unrealized gains or losses on derivatives during the year ended March 31, 2022. Our derivatives of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives.

Other product sales product margins during the year ended March 31, 2022 increased due to an increase in demand for 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 a decline in margin for other natural gas liquids, as favorable supply contracts in the prior year and increased demand in certain markets during the prior year drove favorable sale differentials. Less volatility in the market, for both supply and demand, led to tighter margins for these products during the current period.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the year ended March 31, 2022 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 decrease was primarily due to the disposition of Sawtooth in June 2021 which was partially offset by increased travel as we came out of the pandemic.

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 year ended March 31, 2022, we recorded a net loss of $60.1 million related to the sale of Sawtooth (see Note 17 to our Bakken water disposal businessconsolidated financial statements included in this Annual Report) 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 year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million due to the write down in value of a terminal we have ceased operating.
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Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Other revenues: 
Revenues$— $1,255 $(1,255)
Cost of sales— 1,816 (1,816)
Loss— (561)561 
Expenses: 
General and administrative expenses41,491 47,520 (6,029)
Depreciation and amortization expense6,959 5,062 1,897 
(Gain) loss on disposal or impairment of assets, net(50)11,001 (11,051)
Total expenses48,400 63,583 (15,183)
Operating loss$(48,400)$(64,144)$15,744 

General and Administrative Expenses. The decrease during the year ended March 31, 2022 was due primarily to lower compensation and legal expenses, offset by increased consulting fees. Compensation expense decreased due to lower equity-based compensation, partially 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.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily due to the write-off of a loan receivable related to the construction of a facility (see Note 17 to our consolidated financial statements included in this Annual Report).

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.4 million during the year ended March 31, 2022, compared to $1.9 million during the year ended March 31, 2021. The decrease of $0.5 million during the year ended March 31, 2022 was due primarily to lower earnings from certain membership interests related to specific land and water services operations.

Interest Expense

The following table summarizes the components of our consolidated interest expense for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Senior secured notes$153,750 $24,344 $129,406 
Senior unsecured notes87,766 96,711 (8,945)
Amortization of debt issuance costs16,960 13,420 3,540 
Revolving credit facility10,077 46,500 (36,423)
Other3,087 17,824 (14,737)
Total$271,640 $198,799 $72,841 

The increase of $72.8 million during the year ended March 31, 2022 was primarily due to the issuance of the 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) which resulted in us paying a higher interest rate on certain refinanced indebtedness. This increase was partially offset by the termination of the term credit agreement as well as the repurchases of a portion of our senior unsecured notes to mature in 2023 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report).

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Gain (Loss) on Early Extinguishment of Liabilities, Net

Gain on early extinguishment of liabilities, net was $1.8 million during the year ended March 31, 2022, compared to a loss on early extinguishment of liabilities, net of $16.7 million during the year ended March 31, 2021. During the years ended March 31, 2022 and 2021, the net gain (loss) (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 disposalthe early extinguishment of $33.4 million (see the Sawtooth credit agreement. See Note 167 to our consolidated financial statements included in this Annual Report for a further discussion of both transactions). In addition, we recorded adiscussion.

Other Income (Expense), Net

Other income, net loss of $3.1was $2.3 million on the disposals of certain other assets during the year ended March 31, 2019.2022, compared to other expense, net of $36.5 million during the year ended March 31, 2021. The decrease in other expense, net of $38.8 million during the year ended March 31, 2022 was due primarily to a $40.0 million fee paid to the holders of the 9.00% Class D Preferred Units (“Class D Preferred Units”) during the year ended March 31, 2021 to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the $500.0 million asset-based revolving credit facility (“ABL Facility”) (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.


Income Tax (Expense) Benefit

Income tax expense was $1.0 million during the year ended March 31, 2022, compared to an income tax benefit of $3.4 million during the year ended March 31, 2021. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Noncontrolling interest income was $0.7 million during the year ended March 31, 2022, compared to $0.6 million during the year ended March 31, 2021. The increase of less than $0.1 million during the year ended March 31, 2022 was due primarily to higher income from certain recycling operations, partially offset by a higher loss from operations of the Sawtooth joint venture primarily due to the sale of Sawtooth in June 2021 and lower income from certain water solutions operations.


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Segment Operating Results for the Years Ended March 31, 2021 and 2020

Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated. As previously reported, on July 2, 2019, we acquired all of the assets of Mesquite and on October 31, 2019, we acquired all of the equity interests of Hillstone, thus the fiscal year 2020 results only include a partial year of operations related to these transactions.
 Year Ended March 31,
 20212020Change
 (in thousands, except per barrel and per day amounts)
Revenues:   
Water disposal service fees$308,511 $305,124 $3,387 
Sale of recovered crude oil28,599 59,445 (30,846)
Recycled water3,015 705 2,310 
Other revenues30,861 56,785 (25,924)
Total revenues370,986 422,059 (51,073)
Expenses:   
Cost of sales-excluding impact of derivatives2,557 5,511 (2,954)
Derivative loss (gain)7,065 (39,381)46,446 
Operating expenses142,371 192,987 (50,616)
General and administrative expenses6,403 7,939 (1,536)
Depreciation and amortization expense222,107 163,588 58,519 
Loss on disposal or impairment of assets, net76,942 255,285 (178,343)
Revaluation of liabilities6,261 9,194 (2,933)
Total expenses463,706 595,123 (131,417)
Segment operating loss$(92,720)$(173,064)$80,344 
Produced water processed (barrels per day)
Delaware Basin (1)1,148,582 1,170,158 (21,576)
Eagle Ford Basin78,397 246,784 (168,387)
DJ Basin111,016 164,936 (53,920)
Other Basins26,596 61,091 (34,495)
Total1,364,591 1,642,969 (278,378)
Recycled water (barrels per day)43,503 14,992 28,511 
Total (barrels per day)1,408,094 1,657,961 (249,867)
Skim oil sold (barrels per day)1,957 3,397 (1,440)
Service fees for produced water processed ($/barrel) (2)$0.62 $0.63 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (2)$0.06 $0.12 $(0.06)
Operating expenses for produced water processed ($/barrel) (2)$0.29 $0.40 $(0.11)
(1)    During the year ended March 31, 2020, barrels per day of producedwater processed by the assets acquired in the Mesquite and Hillstone transactions are calculated by the number of days in which we owned the assets.
(2)    Total producedwater barrels processed during the years ended March 31, 2021 and 2020 were 498,075,843 and 485,115,941, respectively.

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in the volume of produced water processed primarily driven by our acquisitions of Mesquite and Hillstone as well as new produced water volumes received upon the completion and commencement of the Partnership’s Poker Lake pipeline. The pipeline was successfully completed in October 2020 with a capacity of over 400,000 barrels per day and connects into our integrated Delaware Basin produced water pipeline infrastructure network. These increases were partially offset by a decrease in the volume of other produced water processed resulting from lower crude oil prices, development activity and production volumes.

Recovered Crude Oil Revenues. The decrease was due primarily to a reduction in the number of producing wells completed in our area of operations, a decrease in the percentage of skim oil volumes recovered per produced water barrel processed and lower crude oil prices. The lower percentage of skim oil volumes recovered was due primarily to an increase in
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produced water transported through pipelines (which contains less oil per barrel of produced water), and the addition of contract structures that allow producers to keep the skim oil recovered from produced water.

Recycled Water Revenues. The increase was due primarily to the timing of our customers completions driven by an increase in drilling and completion activity primarily in the Delaware Basin.

Other Revenues. The decrease was due primarily to reduced customer development activity and needs for these services resulting from the decline in crude oil prices.

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to lower purchasing and transportation costs related to our brackish non-potable water and crude oil sales.

Derivative Loss (Gain). During the year ended March 31, 2021, we had $24.5 million of net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. During the year ended March 31, 2020, we had $29.9 million of net unrealized gains on derivatives and $9.5 million of net realized gains on derivatives. In June 2019, we settled derivative contracts that had scheduled settlement dates from April through December 2020 and recorded a gain of $1.9 million on those derivatives.

Operating and General and Administrative Expenses. The decrease was due primarily to the deployment of automation and subsequent reduction in employee headcount, reduced equipment rental (including generators) and associated diesel fuel and repairs and lower maintenance expense. In addition, acquisition expenses were lower by $4.1 million as we did not close on any acquisitions during the year ended March 31, 2021.

Depreciation and Amortization Expense.The increase was due primarily to Mesquite and Hillstone acquisitions completed in the prior year and newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2018,2021, we recordedrecorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report);
an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
a net loss of $8.2$6.7 million on the disposalsrelated to write-down or write off of certain assets, partially offsetincluding facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $1.3$14.0 million forrelated to the terminationsale of certain permits, land and a non-compete agreement, which included the carrying value of the non-compete agreement intangible asset that was written offsaltwater disposal facility (see Note 717 to our consolidated financial statements included in this Annual Report).

During the year ended March 31, 2020, we recorded:

a goodwill impairment charge of $250.0 million related to the current macroeconomic conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, resulting in expected decreases in future cash flows for certain of our assets (see Note 5 to our consolidated financial statements included in this Annual Report);
an impairment charge of $13.5 million related to certain inactive saltwater disposal facilities;
a net loss of $9.2 million on the disposals of certain other assets;
a gain of $14.5 million for the sale of certain water permits (see Note 17 to our consolidated financial statements included in this Annual Report); and
a gain of $1.0 million for cash received related to a loan receivable that was previously written off.

Revaluation of Liabilities.The revaluation of liabilities representsDuring the changeyear ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations. The reductioncombinations due primarily to higher expected production from new customers, resulting in expense duringan increase to the expected future royalty payment.
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During the year ended March 31, 20192020, a portion of the revaluation of liabilities represented the change in the valuation of our contingent consideration liability issued by us as part of a business combination. Under the agreement, we were required to make additional payments to the seller based on the volume of produced water processed by the assets acquired. During the year ended March 31, 2020, the thresholds for the volume of produced water processed were surpassed, thus triggering our obligation to pay the seller.

During the year ended March 31, 2020, there was a reduction in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers and an increase in facilities due to acquisitions, resulting in a decrease to the expected future royalty payment.

Crude Oil Logistics

The expensefollowing table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$1,574,699 $2,383,812 $(809,113)
Crude oil transportation and other153,588 184,129 (30,541)
Total revenues (1)1,728,287 2,567,941 (839,654)
Expenses:   
Cost of sales-excluding impact of derivatives1,473,330 2,347,863 (874,533)
Derivative loss (gain)49,314 (35,736)85,050 
Operating expenses56,918 61,708 (4,790)
General and administrative expenses8,038 6,723 1,315 
Depreciation and amortization expense60,874 70,759 (9,885)
Loss (gain) on disposal or impairment of assets, net384,143 (1,144)385,287 
Total expenses2,032,617 2,450,173 (417,556)
Segment operating (loss) income$(304,330)$117,768 $(422,098)
Crude oil sold (barrels)38,349 42,799 (4,450)
Crude oil transported on owned pipelines (barrels)32,797 45,884 (13,087)
Crude oil storage capacity - owned and leased (barrels) (2)5,239 5,362 (123)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 2,062 (561)
Crude oil inventory (barrels) (2)1,201 1,111 90 
Crude oil sold ($/barrel)$41.062 $55.698 $(14.636)
Cost per crude oil sold ($/barrel) (3)$38.419 $54.858 $(16.439)
Crude oil product margin ($/barrel) (3)$2.643 $0.840 $1.803 
(1)    Revenues include $6.7 million and $18.2 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The decrease was due primarily to a decrease in crude oil prices and sales volumes during the year ended March 31, 20182021, compared to the year ended March 31, 2020. The volumes decreased due to changes in the method of delivery to the market in the Permian region, as a significant amount of production switched to long haul pipeline owned and controlled by others.

Crude Oil Transportation and Other Revenues. The decrease was primarily due to our Grand Mesa Pipeline, which decreased revenues by $32.8 million during the year ended March 31, 2021, compared to the year ended March 31, 2020. During the year ended March 31, 2021, financial volumes on the Grand Mesa Pipeline averaged approximately 94,000 barrels per day, compared to 131,000 barrels per day for the year ended March 31, 2020 (volume amounts are from both internal and
67



external parties) primarily due to the court approved rejection of the Extraction transportation agreement (see Note 17 to our consolidated financial statements included in this Annual Report).

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to higher actuala decrease in crude oil prices and expected production from new customers, resulting in an increasereduced volumes during the year ended March 31, 2021, compared to the expected future royalty payment.year ended March 31, 2020.


Derivative Loss (Gain). Our cost of sales during the year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives. The losses are due to a very volatile pricing market during the year ended March 31, 2021. Our cost of sales during the year ended March 31, 2020 included $24.4 million of net realized gains on derivatives and $11.3 million of net unrealized gains on derivatives. In March 2020, we closed realized derivative contracts that had scheduled settlement dates from May 2020 through June 2020, which accounted for $16.7 million of the realized gains for the prior year.

Crude Oil Product Margin. The increase was due to inventory purchased during the three months ended June 30, 2020 at lower prices and held for sale during the three months ended September 30, 2020 and the three months ended December 31, 2020 when prices recovered.

Operating and General and Administrative Expenses.Expenses decreased compared to the prior year due to a decrease of utilities, as lower volumes were being shipped on the Grand Mesa Pipeline and other cost cutting measures which were partially offset by the write off of a $5.7 million receivable from Extraction (see Note 17 to our consolidated financial statements included in this Annual Report).

Depreciation and Amortization Expense. The decrease was due to the retirement of certain assets and other assets being fully depreciated or amortized during the year ended March 31, 2020.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report), and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report). During the year ended March 31, 2020, we recorded a net gain of $1.1 million related to the disposal of certain assets.



















68




Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)(2)$1,124,087 $2,394,663 $(1,270,576)
Cost of sales-excluding impact of derivatives (3)1,108,493 2,367,850 (1,259,357)
Derivative loss (gain)930 (3,225)4,155 
Product margin14,664 30,038 (15,374)
Propane sales:
Revenues (1)1,027,582 846,756 180,826 
Cost of sales-excluding impact of derivatives949,402 766,521 182,881 
Derivative loss10,994 3,536 7,458 
Product margin67,186 76,699 (9,513)
Butane sales:
Revenues (1)517,857 564,016 (46,159)
Cost of sales-excluding impact of derivatives469,394 486,777 (17,383)
Derivative loss (gain)22,353 (8,288)30,641 
Product margin26,110 85,527 (59,417)
Other product sales:
Revenues-excluding impact of derivatives (1)446,744 775,458 (328,714)
Cost of sales-excluding impact of derivatives424,191 732,967 (308,776)
Derivative gain(7,078)(2,846)(4,232)
Product margin29,631 45,337 (15,706)
Service revenues:
Revenues (1)33,915 40,216 (6,301)
Cost of sales4,751 9,207 (4,456)
Product margin29,164 31,009 (1,845)
Expenses:
Operating expenses55,273 77,980 (22,707)
General and administrative expenses8,507 12,644 (4,137)
Depreciation and amortization expense29,184 27,930 1,254 
Loss on disposal or impairment of assets, net3,350 7,645 (4,295)
Total expenses96,314 126,199 (29,885)
Segment operating income$70,441 $142,411 $(71,970)
69


  Year Ended March 31,  
  2019 2018 Change
  (in thousands, except per gallon amounts)
Propane sales:      
Revenues (1) $1,179,087
 $1,203,486
 $(24,399)
Cost of sales-excluding impact of derivatives 1,111,678
 1,165,414
 (53,736)
Cost of sales-derivative loss (gain) 5,856
 (5,577) 11,433
Product margin 61,553
 43,649
 17,904
       
Butane sales:      
Revenues (1) 637,076
 562,066
 75,010
Cost of sales-excluding impact of derivatives 609,833
 535,017
 74,816
Cost of sales-derivative (gain) loss (1,264) 19,616
 (20,880)
Product margin 28,507
 7,433
 21,074
       
Other product sales:      
Revenues (1) 599,166
 432,570
 166,596
Cost of sales-excluding impact of derivatives 570,866
 414,980
 155,886
Cost of sales-derivative loss (gain) 1,001
 (173) 1,174
Product margin 27,299
 17,763
 9,536
       
Service revenues:      
Revenues (1) 23,003
 22,548
 455
Cost of sales 3,030
 3,930
 (900)
Product margin 19,973
 18,618
 1,355
       
Expenses:     
Operating expenses 41,360
 32,792
 8,568
General and administrative expenses 5,672
 5,331
 341
Depreciation and amortization expense 25,997
 24,937
 1,060
Loss on disposal or impairment of assets, net 67,213
 117,516
 (50,303)
Total expenses 140,242
 180,576
 (40,334)
Segment operating loss $(2,910) $(93,113) $90,203
       
Liquids storage capacity - owned and leased (gallons) (2) 397,343
 438,968
 (41,625)
       
Propane sold (gallons) 1,383,986
 1,361,173
 22,813
Propane sold ($/gallon) $0.852
 $0.884
 $(0.032)
Cost per propane sold ($/gallon) $0.807
 $0.852
 $(0.045)
Propane product margin ($/gallon) $0.045
 $0.032
 $0.013
Propane inventory (gallons) (2) 44,757
 48,928
 (4,171)
Propane storage capacity leased to third parties (gallons) (2) 30,440
 29,662
 778
       
Butane sold (gallons) 610,968
 544,750
 66,218
Butane sold ($/gallon) $1.043
 $1.032
 $0.011
Cost per butane sold ($/gallon) $0.996
 $1.018
 $(0.022)
Butane product margin ($/gallon) $0.047
 $0.014
 $0.033
Butane inventory (gallons) (2) 21,677
 15,385
 6,292
Butane storage capacity leased to third parties (gallons) (2) 62,185
 51,660
 10,525
       
Other products sold (gallons) 498,751
 400,405
 98,346
Other products sold ($/gallon) $1.201
 $1.080
 $0.121
Cost per other products sold ($/gallon) $1.147
 $1.036
 $0.111
Other products product margin ($/gallon) $0.054
 $0.044
 $0.010
Other products inventory (gallons) (2) 9,158
 5,822
 3,336

Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (4)427,975 400,301 27,674 
Refined products sold (gallons)834,717 1,272,546 (437,829)
Refined products sold ($/gallon)$1.347 $1.890 $(0.543)
Cost per refined products sold ($/gallon) (5)$1.328 $1.861 $(0.533)
Refined products product margin ($/gallon) (5)$0.019 $0.029 $(0.010)
Refined products inventory (gallons) (4)1,223 2,391 (1,168)
Propane sold (gallons)1,364,224 1,478,759 (114,535)
Propane sold ($/gallon)$0.753 $0.573 $0.180 
Cost per propane sold ($/gallon) (5)$0.696 $0.518 $0.178 
Propane product margin ($/gallon) (5)$0.057 $0.055 $0.002 
Propane inventory (gallons) (4)51,026 57,221 (6,195)
Propane storage capacity leased to third parties (gallons) (4)53,947 46,066 7,881 
Butane sold (gallons)655,256 814,528 (159,272)
Butane sold ($/gallon)$0.790 $0.692 $0.098 
Cost per butane sold ($/gallon) (5)$0.716 $0.598 $0.118 
Butane product margin ($/gallon) (5)$0.074 $0.094 $(0.020)
Butane inventory (gallons) (4)20,066 24,808 (4,742)
Butane storage capacity leased to third parties (gallons) (4)56,700 33,894 22,806 
Other products sold (gallons)471,245 602,872 (131,627)
Other products sold ($/gallon)$0.948 $1.286 $(0.338)
Cost per other products sold ($/gallon) (5)$0.900 $1.216 $(0.316)
Other products product margin ($/gallon) (5)$0.048 $0.070 $(0.022)
Other products inventory (gallons) (4)19,195 26,126 (6,931)
(1)Revenues include $23.3 million and $4.7 million of intersegment sales during the years ended March 31, 2019 and 2018, respectively, that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2019 and March 31, 2018, respectively.
(1)    Revenues include $6.1 million and $5.0 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Revenues include $10.3 million of intersegment sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(3)    Cost of sales include $8.2 million of intersegment cost of sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(4)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(5)    Cost and product margin per gallon excludes the impact of derivatives.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales, excluding the impact of derivatives, were due to a decrease in refined products prices and volumes due to the sizable reduction in demand for both gasoline and diesel products due to the COVID-19 pandemic. There was also a large decrease in volumes due to the elimination of our sales in the Northeast and Southeast due to our non-compete clause with the purchaser of our TPSL business.

Refined Products Derivative Loss (Gain). Our margin during the year ended March 31, 2021 included a loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions. Our margin during the year ended March 31, 2020 included a gain of $3.2 million from our risk management activities due primarily to unrealized gains on our open forward physical positions and decreases in NYMEX futures prices on our short future positions.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreasesincreases in revenues and cost of sales-excluding impact of derivatives were due primarily to increased commodity prices in the fourth quarter of the year ended March 31, 2021, as a declineresult of winter storm Uri in product pricingFebruary 2021. These increases were partially offset by lower volumes as a result of lower commercial and lower railcar costs.industrial demand due to the COVID-19 pandemic.
70


Cost of Sales-Derivatives
Propane Derivative Loss. Our cost of wholesale propane sales included $1.4$3.3 million of net unrealized lossesgains on derivatives and $4.4$14.3 million of net realized losses on derivatives during the year ended March 31, 2019.2021. During the year ended March 31, 2018,2020, our cost of wholesale propane sales included $1.0$1.5 million of net unrealized gainslosses on derivatives and $4.6$2.0 million of net realized gainslosses on derivatives.

Propane product margins per gallon of propane sold were higher during the year ended March 31, 20192021 than during the year ended March 31, 20182020 due primarily to favorable market conditions.inventory values aligning with reduced commodity prices at index markets as well as the extreme cold weather in February 2021.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increasesdecreases in revenues and cost of sales-excluding impact of derivatives in butane were due primarily to higher commodity prices in the first six months of the year, partially offset by declining commodity prices in the latter half of the year. Volumes increasedlower product demand which decreased due to favorable market conditions.lower gasoline blending volumes and decreased export sales related to the COVID-19 pandemic.

Cost of Sales-DerivativesButane Derivative Loss (Gain). Our cost of butane sales during the year ended March 31, 20192021 included $1.5$3.2 million of net unrealized gainslosses on derivatives and $0.3$19.1 million of net realized losses on derivatives. Our cost of butane sales included $0.5 million of net unrealized losses on derivatives and $19.1$8.8 million of net realized lossesgains on derivatives during the year ended March 31, 2018.2020.

Butane product margins per gallon of butane sold were higherlower during the year ended March 31, 20192021 than during the year ended March 31, 20182020 due primarily to a strong pricingthe weaker domestic market and generally strong demand.demand due to COVID-19.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. Other product volumes increase was facilitated by a price arbitrage allowing for products to be sold across markets.

Cost of Sales-Derivatives. OurThe decreases in revenues and cost of sales - excluding the impact of other products included less than $0.1 million of net unrealized gains on derivatives, were due to lower commodity prices and $1.0 million of net realized losses on derivatives duringlower demand due to the year ended March 31, 2019.lockdowns related to the COVID-19 pandemic.

Other Products Derivative Gain. Our cost of sales of other products during the year ended March 31, 20182021 included $0.1$0.5 million of net unrealized gains on derivatives and $0.1$6.6 million of net realized gains on derivatives. Our cost of sales of other products included $0.6 million of net unrealized losses on derivatives and $3.4 million of net realized gains on derivatives during the year ended March 31, 2020.

Other product sales product margins during the year ended March 31, 2019 were higher2021 decreased primarily due to softer product demand during the COVID-19 pandemic and associated economic slowdown. In addition, the margin for the year ended March 31, 2020, included a strong pricing environment and higher than anticipated production.biodiesel tax credit of $13.8 million. The impact of the biodiesel tax credit for the year March 31, 2021 was approximately $0.4 million.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The increasedecrease during the year ended March 31, 20192021 was primarily related to an increase in revenues at our Port Hudson terminalweaker demand as well as high railcar fleet utilization.producers shut-in and curtailed production.

Operating and General and Administrative Expenses. Expenses were higherdecreased for the year ended March 31, 2021 due to an increase in employee commissions resulting from increased profit margins, increased expenses relatedlower volumes and services rendered as well as reduced costs with lower incentive compensation and restricted travel due to the Sawtooth joint venture, increased expenses in March related to our natural gas liquids terminal acquisition and a credit in the prior year for ad valorem taxes.COVID-19.

Depreciation and Amortization Expense. Expense for the current year ended March 31, 2021 was consistent withhigher due to the acceleration of depreciation expense prior year.to the sale of a terminal facility.

Loss on Disposal or Impairment of Assets, Net. During the yearsyear ended March 31, 2019 and 2018,2021, we recorded goodwillan impairment chargesloss of $66.2approximately $3.3 million and $116.9 million, respectively, within our natural gas liquids salt cavern storage reporting unit due to the decreased demand for natural gas liquid storage and resulting declinewrite down in revenues and earnings as compared to actual and projected resultsvalue of prior and future periods (see Note 6 to our consolidated financial statements included in this Annual Report). During the years ended March 31, 2019 and 2018,a terminal we recorded a net loss of $1.0 million and $0.6 million, respectively, related to the retirement of assets.


Refined Productsand Renewables
The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated.
  Year Ended March 31,  
  2019 2018 Change
  (in thousands, except per barrel amounts)
Refined products sales:      
Revenues-excluding impact of derivatives (1) $17,951,780
 $11,827,222
 $6,124,558
Cost of sales-excluding impact of derivatives 17,937,504
 11,709,786
 6,227,718
Derivative (gain) loss (22,023) 77,055
 (99,078)
Product margin 36,299
 40,381
 (4,082)
       
Renewables sales:      
Revenues-excluding impact of derivatives 270,302
 373,669
 (103,367)
Cost of sales-excluding impact of derivatives 276,094
 362,457
 (86,363)
Derivative (gain) loss (2,661) 1,467
 (4,128)
Product (loss) margin (3,131) 9,745
 (12,876)
       
Service fees and other revenues 15,605
 300
 15,305
       
Expenses:   

  
Operating expenses 13,714
 14,057
 (343)
General and administrative expenses 9,108
 8,433
 675
Depreciation and amortization expense 1,518
 1,294
 224
Gain on disposal or impairment of assets, net (3,026) (30,098) 27,072
Total expense (income), net 21,314
 (6,314) 27,628
Segment operating income $27,459
 $56,740
 $(29,281)
       
Gasoline sold (barrels) 173,475
 108,427
 65,048
Diesel sold (barrels) 53,662
 56,020
 (2,358)
Ethanol sold (barrels) 2,553
 3,438
 (885)
Biodiesel sold (barrels) 991
 2,079
 (1,088)
Refined products and renewables storage capacity - leased (barrels) (2) 9,745
 9,911
 (166)
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2) 235
 1,068
 (833)
Gasoline inventory (barrels) (2) 2,807
 3,367
 (560)
Diesel inventory (barrels) (2) 1,258
 1,419
 (161)
Ethanol inventory (barrels) (2) 1,640
 701
 939
Biodiesel inventory (barrels) (2) 310
 261
 49
Refined products sold ($/barrel) $79.035
 $71.921
 $7.114
Cost per refined products sold ($/barrel) $78.875
 $71.676
 $7.199
Refined products product margin ($/barrel) $0.160
 $0.245
 $(0.085)
Renewable products sold ($/barrel) $76.270
 $67.730
 $8.540
Cost per renewable products sold ($/barrel) $77.154
 $65.964
 $11.190
Renewable products product (loss) margin ($/barrel) $(0.884) $1.766
 $(2.650)
(1)Revenues include $0.3 million of intersegment sales during the year ended March 31, 2018 that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2019 and March 31, 2018, respectively.

Refined Products Revenues-Excluding Impact of Derivatives and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues-excluding impact of derivatives and cost of sales-excluding impact of derivatives were due to an increase in refined products prices and increased volumes. The increase in prices was due primarily to supply and demand for refined

fuels at our wholesale locations. The increased volumes were due primarily to an expansion of our refined products operations and the continued demand for motor fuels.have ceased operating. During the year ended March 31, 2019, Gulf Coast prices increased less than during2020, we recorded an impairment of $7.7 million due to adjusting the year endedcost basis of pipeline linefill to the market price of propane as of March 31, 2018, which negatively affected our margins-excluding impact of derivatives.

2020.
Refined Products-Derivative (Gain) Loss. Our margin during the year ended March 31, 2019 included a gain of $22.0 million from our risk management activities due primarily to NYMEX futures prices decreasing on our short future positions. Our margin during the year ended March 31, 2018 included a loss of $77.1 million from our risk management activities due primarily to NYMEX futures prices increasing on our short future positions.

71

Renewables Revenues-Excluding Impact of Derivatives and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues-excluding impact of derivatives and cost of sales-excluding impact of derivatives were due primarily to decreased volumes from the loss of a marketing contract with E Energy Adams, LLC in December 2017, partially offset by an increase in renewables prices due primarily to supply and demand for renewable fuels. In addition, the favorable margin for the year ended March 31, 2018 included the impact of the biodiesel tax credit being reinstated in February 2018 related to calendar year 2017. Currently, the biodiesel tax credit has not been reinstated for calendar year 2018.

Renewables-Derivative (Gain) Loss. Our margin during the year ended March 31, 2019 included a gain of $2.7 million from our risk management activities due primarily to unrealized gains on our open forward positions. Our margin during the year ended March 31, 2018 included a loss of $1.5 million from our risk management activities due primarily to NYMEX futures prices increasing on our short future positions, partially offset by unrealized gains on our open forward positions.

Service Fees and Other Revenues. The increase was due primarily to an early termination settlement for one our sublease agreements during the three months ended June 30, 2018 and the reclassification of sublease revenue to Service Fees and Other Revenues beginning April 1, 2018 in conjunction with the adoption of ASC 606. See Note 15 to our consolidated financial statements included in this Annual Report for a further discussion.

Operating and General and Administrative Expenses. The increase was due primarily to expansion of our refined products operations into gas blending, partially offset by lower environmental expense during the year ended March 31, 2019 from an insurance recovery received during the three months ended June 30, 2018 related to a historical environmental indemnification agreement.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions during the year ended March 31, 2019.

Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2019, we recorded a gain of $3.0 million on the sale of our previously held 20% interest in E Energy Adams, LLC (see Note 2 to our consolidated financial statements included in this Annual Report). During the year ended March 31, 2018, we recognized $30.1 million of the deferred gain from the sale of the general partner interest in TLP in February 2016. There is not a similar amount of deferred gain recognized during the year ended March 31, 2019 due to our adoption of ASC 606. See Note 15 to our consolidated financial statements included in this Annual Report for a further discussion of the reasons for the realization of the deferred gain.


Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Other revenues: 
Revenues$1,255 $1,038 $217 
Cost of sales1,816 1,774 42 
Loss(561)(736)175 
Expenses: 
Operating expenses— 318 (318)
General and administrative expenses47,520 86,358 (38,838)
Depreciation and amortization expense5,062 3,035 2,027 
Loss on disposal or impairment of assets, net11,001 — 11,001 
Total expenses63,583 89,711 (26,128)
Operating loss$(64,144)$(90,447)$26,303 
  Year Ended March 31,  
  2019 2018 Change
  (in thousands)
Other revenues:      
Revenues $1,362
 $1,174
 $188
Cost of sales 1,929
 530
 1,399
(Loss) margin (567) 644
 (1,211)
       
Expenses:      
Operating expenses 1,605
 1,173
 432
General and administrative expenses 79,627
 75,158
 4,469
Depreciation and amortization expense 3,018
 3,779
 (761)
Loss on disposal or impairment of assets, net 889
 8
 881
Total expenses 85,139
 80,118
 5,021
Operating loss $(85,706) $(79,474) $(6,232)

General and Administrative Expenses. The increasedecrease during the year ended March 31, 20192021 was due primarily to higherlower equity-based compensation expense.expense and acquisition expenses. During the year ended March 31, 2019,2021, equity-based compensation expense was $37.6$6.7 million, compared to $35.2$26.5 million during the year ended March 31, 2018. The increase is primarily due2020. During the year ended March 31, 2021, acquisition expenses were $1.7 million, compared to an increase in annual bonuses paid in common units of approximately $7.0$15.6 million and the cancellation of our Performance Awards during the year ended March 31, 2019. This increase was partially offset by a2020. The driver behind the decrease specifically related to our Service Awards of approximately $4.2 million, whichin acquisition expenses was primarily due to the vestingexpenses incurred in connection with our acquisitions of Service Awards with higher grant date fair values duringboth Mesquite and Hillstone in the year ended March 31, 2018. For further discussion of the Service Awards, see Note 10 to our consolidated financial statements included in this Annual Report. The increase in equity-based compensation was primarily offset by a decrease in legal expenses.2020.

Depreciation and Amortization Expense. The decrease was due primarily to certain information technology equipment which was fully depreciated at the end of March 31, 2018.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily 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 (see Note 17 to our consolidated financial statements included in this Annual Report ) and a loss from the write-off of installment payments made in connection with an option agreement to invest in a third party.

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.9 million during the year ended March 31, 2021, compared to $1.3 million during the year ended March 31, 2020. The increase of $0.6 million during the year ended March 31, 2021 was due primarily to higher earnings from certain membership interests acquired in November 2019 we soldrelated to specific land and water services operations, partially offset by a higher loss from our 50% interest in Victory Propanean aircraft company during the year ended March 31, 2021.

Interest Expense

The following table summarizes the components of our consolidated interest expense for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Senior unsecured notes$96,711 $102,289 $(5,578)
Revolving credit facility46,500 57,470 (10,970)
Senior secured notes24,344 — 24,344 
Amortization of debt issuance costs13,420 10,901 2,519 
Other17,824 10,524 7,300 
Total$198,799 $181,184 $17,615 

The increase of $17.6 million during the year ended March 31, 2021 was due to the issuance of the 2026 Senior Secured Notes. This increase was offset by repurchases of a portion of our senior unsecured notes to mature in 2023, 2025 and as consideration we received a promissory note from Victory Propane. We discounted the promissory note to its net present value and recorded a loss of $0.9 million2026 (see Note 137 to our consolidated financial statements included in this Annual Report).
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(Loss) Gain on Early Extinguishment of Liabilities, Net
Equity in Earnings
Loss on early extinguishment of Unconsolidated Entities

The decrease of $5.0liabilities, net was $16.7 million during the year ended March 31, 2019 was due primarily2021, compared to the salea gain on early extinguishment of our investments in Glass Mountain and E Energy Adams, LLC. On December 22, 2017, we sold our previously held 50% interest in Glass Mountain and on May 3, 2018, we sold our previously held 20% interest in E Energy Adams, LLC. These decreases were partially offset by earnings from our 50% interest in a water services company that we acquired as partliabilities, net of an acquisition in August 2018. See Note 2 and Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

Interest Expense

Interest expense includes interest charged on the revolving credit facilities, 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 decrease of $34.4$1.3 million during the year ended March 31, 2019 was partially due to2020. During the repurchase of all senior secured notes on December 29, 2017. We also repurchased $84.1 million of the 2023 Notes (as defined herein) and $110.9 million of the 2025 Notes (as defined herein) during the yearyears ended March 31, 2018. Also contributing to the decrease is the October 16, 2018 redemption of the remaining outstanding 2021 Notes (as defined

herein) and the March 15, 2019 redemption of the remaining outstanding 2019 Notes. See Note 8 to our consolidated financial statements included in this Annual Report for a further discussion.

Loss on Early Extinguishment of Liabilities, Net

During the year ended March 31, 2019,2020, the net loss(loss) gain (inclusive of debt issuance costs written off) relates to the early extinguishment of a portion of the outstanding senior unsecured notes and the redemption of the 2019 Notes and 2021 Notes. During the year ended March 31, 2018, the net loss (inclusive of debt issuance costs written off) relates to the early extinguishment of all of the senior secured notes and a portion of the senior unsecured notes. See Note 87 to our consolidated financial statements included in this Annual Report for a further discussion.

Other (Expense) Income, Net


The following table summarizes the components of other (expense) income,Other expense, net for the periods indicated:
 Year Ended March 31,
 2019 2018
 (in thousands)
Interest income (1)$5,199
 $6,297
Gavilon legal matter settlement (2)(34,788) 
Other (3)(357) 656
Other (expense) income, net$(29,946) $6,953
(1)During the year ended March 31, 2019, this relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility that is utilized by a third party. During the year ended March 31, 2018, this relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility that is utilized by a third party and to a loan receivable from Victory Propane (see Note 13 to our consolidated financial statements included in this Annual Report for a further discussion).
(2)Represents the accrual for the estimated cost of the settlement of the Gavilon legal matter (see Note 9 to our consolidated financial statements included in this Annual Report for a further discussion).
(3)During the year ended March 31, 2019, this relates primarily to unrealized losses on marketable securities. During the year ended March 31, 2018, this relates primarily to proceeds from a litigation settlement.

Income Tax Expense

Income tax expense was $1.2$36.5 million during the year ended March 31, 2019,2021, compared to other income, tax expensenet of $1.4$1.7 million during the year ended March 31, 2018.2020. The increase in other expense, net of $38.2 million during the year ended March 31, 2021 was due primarily to a $40.0 million fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.

Income Tax Benefit (Expense)

Income tax benefit was $3.4 million during the year ended March 31, 2021, compared to income tax expense of $0.3 million during the year ended March 31, 2020. The increase in the income tax benefit during the year ended March 31, 2021 was primarily due to a full year of Hillstone operations during the year ended March 31, 2021 compared to five months of Hillstone operations during the year ended March 31, 2020. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.


Noncontrolling Interests - Redeemable and Non-redeemable

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The increase in the noncontrolling interest loss of $21.9income was $0.6 million during the year ended March 31, 2019 was due primarily2021, compared to a noncontrolling interest loss from operations of the Sawtooth joint venture, in which we sold a 28.5% interest in March 2018.

Segment Operating Results for the Years Ended March 31, 2018 and 2017


69



Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
  Year Ended March 31,  
  2018 2017 Change
  (in thousands, except per barrel amounts)
Revenues:      
Crude oil sales $2,151,203
 $1,603,667
 $547,536
Crude oil transportation and other 122,786
 70,027
 52,759
Total revenues (1) 2,273,989
 1,673,694
 600,295
Expenses:  
  
  
Cost of sales-excluding impact of derivatives 2,120,640
 1,573,246
 547,394
Cost of sales-derivative loss 7,021
 5,579
 1,442
Operating expenses 47,846
 41,535
 6,311
General and administrative expenses 6,584
 5,961
 623
Depreciation and amortization expense 80,387
 54,144
 26,243
(Gain) loss on disposal or impairment of assets, net (111,393) 10,704
 (122,097)
Total expenses 2,151,085
 1,691,169
 459,916
Segment operating income (loss) $122,904
 $(17,475) $140,379
       
Crude oil sold (barrels) 39,626
 34,212
 5,414
Crude oil transported on owned pipelines (barrels) 33,454
 6,365
 27,089
Crude oil storage capacity - owned and leased (barrels) (2) 6,159
 7,024
 (865)
Crude oil storage capacity leased to third parties (barrels) (2) 2,641
 3,717
 (1,076)
Crude oil inventory (barrels) (2) 1,219
 2,844
 (1,625)
Crude oil sold ($/barrel) $54.288
 $46.874
 $7.414
Cost per crude oil sold ($/barrel) $53.694
 $46.148
 $7.546
Crude oil product margin ($/barrel) $0.594
 $0.726
 $(0.132)
(1)Revenues include $13.9 million and $6.8 million of intersegment sales during the years ended March 31, 2018 and 2017, respectively, that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2018 and March 31, 2017, respectively.

Crude Oil Sales Revenues.The increase was due primarily to an increase in crude oil prices and sales volumes during the year ended March 31, 2018, compared to the year ended March 31, 2017. This segment continued to be impacted by competition and low margins in the majority of the basins across the United States and we continue to market crude volumes in these basins to support our various pipeline, terminal and transportation assets. Additionally, we bear the cost of certain minimum volume commitments on third-party crude oil pipelines in various basins which are currently not profitable.

Crude Oil Transportation and Other Revenues.The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased revenues by $55.0$1.8 million during the year ended March 31, 2018, compared to the year ended March 31, 2017.2020. The increase was also due to increased volumes related to production growth in the DJ Basin. During the year ended March 31, 2018, approximately 33.5 million barrelsnoncontrolling interest income of crude oil were transported on the Grand Mesa Pipeline, which averaged approximately 92,000 barrels per day and financial volumes averaged approximately 96,000 barrels per day (volume amounts are from both internal and external parties). Higher revenues in our trucking operations during the year ended March 31, 2018 were due primarily to increased demand for transportation services, compared to the year ended March 31, 2017, and were partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the year ended March 31, 2018, compared to the year ended March 31, 2017.

Cost of Sales-Excluding Impact of Derivatives.The increase was due primarily to an increase in crude oil prices during the year ended March 31, 2018, compared to the year ended March 31, 2017.


Cost of Sales-Derivatives. Our cost of sales during the year ended March 31, 2018 included $4.2 million of net realized losses on derivatives and $2.8 million of net unrealized losses on derivatives. Our cost of sales during the year ended March 31, 2017 included $7.1 million of net realized losses on derivatives and $1.5 million of net unrealized gains on derivatives.

Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased expenses by $8.0$2.4 million during the year ended March 31, 2018, compared to the year ended March 31, 2017. This increase was partially offset by lower repair and maintenance expense associated with having a newer fleet of barges and a smaller fleet of trucks, as well as the timing of repairs, and lower property taxes due to decreased inventory.

Depreciation and Amortization Expense.The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased depreciation and amortization expense by $23.0 million during the year ended March 31, 2018, compared to the year ended March 31, 2017. Also contributing to the increase was higher depreciation expense related to other capital projects being placed into service.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2018, we recorded a gain of $108.6 million on the sale of our previously held 50% interest in Glass Mountain (see Note 16 to our consolidated financial statements included in this Annual Report). In addition, we recorded a net gain of $2.8 million on the sales of excess pipe and certain other assets. During the year ended March 31, 2017, we recorded a net loss of $6.5 million on the sales of certain assets and a loss of $4.2 million due to the write-down of certain other assets.


Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:
  Year Ended March 31,  
  2018 2017 Change
  (in thousands, except per barrel and per day amounts)
Revenues:  
  
  
Wastewater disposal service fees $149,114
 $110,049
 $39,065
Sale of recovered hydrocarbons 58,948
 31,103
 27,845
Other service revenues 21,077
 18,449
 2,628
Total revenues 229,139
 159,601
 69,538
Expenses:  
  
  
Cost of sales-excluding impact of derivatives 2,150
 2,071
 79
Cost of sales-derivative loss 17,195
 1,997
 15,198
Operating expenses 105,200
 85,562
 19,638
General and administrative expenses 2,623
 2,469
 154
Depreciation and amortization expense 98,623
 101,758
 (3,135)
Loss (gain) on disposal or impairment of assets, net 6,863
 (85,560) 92,423
Revaluation of liabilities 20,716
 6,717
 13,999
Total expenses 253,370
 115,014
 138,356
Segment operating (loss) income $(24,231) $44,587
 $(68,818)
       
Wastewater processed (barrels per day)      
Permian Basin 289,360
 184,702
 104,658
Eagle Ford Basin 235,713
 208,649
 27,064
DJ Basin 113,771
 68,253
 45,518
Other Basins 68,466
 40,185
 28,281
Total 707,310
 501,789
 205,521
Solids processed (barrels per day) 5,662
 3,056
 2,606
Skim oil sold (barrels per day) 3,210
 1,989
 1,221
Service fees for wastewater processed ($/barrel) $0.58
 $0.60
 $(0.02)
Recovered hydrocarbons for wastewater processed ($/barrel) $0.23
 $0.17
 $0.06
Operating expenses for wastewater processed ($/barrel) $0.41
 $0.47
 $(0.06)

Wastewater Disposal Service Fee Revenues. The increase was due primarily to an increase in the volume of wastewater processed, partially offset by higher volumes in areas with lower fees. We continue to benefit from the increased rig counts as compared to the prior year in the basins in which we operate, particularly in the Permian Basin.

Recovered Hydrocarbon Revenues. The increase was due primarily to an increase in the volume of wastewater processed, an increase in the amount of hydrocarbons per barrel of wastewater processed and an increase in crude oil prices.

Other Service Revenues.The increase was due primarily to an increase in solids disposal revenues and water pipeline revenues due to increased volumes. These increases were partially offset by a decrease in freshwater revenues due to the sale of Grassland Water Solutions, LLC (“Grassland”) in November 2016 (see below discussion of the loss on the sale of Grassland).

Cost of Sales-Excluding Impact of Derivatives. Cost of Sales-Excluding Impact of Derivatives was consistent between the current year and prior year.

Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the year ended March 31, 2018 included $13.7 million of net unrealized losses on derivatives and $3.5 million of net realized losses on derivatives. Our cost of sales during the year ended March 31, 2017 included $4.1 million of

net realized losses on derivatives and the reversal of $2.1 million of net unrealized losses on derivatives at March 31, 2016 as there were no open derivatives at March 31, 2017.

Operating and General and Administrative Expenses. The increase was due primarily to higher costs of operations of water disposal wells due to higher volumes processed, partially offset by cost reduction efforts. Due to the higher volumes processed, our cost per barrel has decreased, as shown in the table above.

Depreciation and Amortization Expense.The decrease was due primarily to lower amortization expense from the write-off of an intangible asset during the year ended March 31, 2017 as well as certain intangible assets being fully amortized during the year ended March 31, 2017, partially offset by acquisitions and developed facilities (see Note 7 to our consolidated financial statements included in this Annual Report).

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2018, we recorded a loss of $8.2 million on the disposals of certain assets, partially offset by a gain of $1.3 million for the termination of a non-compete agreement, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7 to our consolidated financial statements included in this Annual Report).

During the year ended March 31, 2017, we recorded:

an adjustment of $124.7 million to the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016 (see Note 6 to our consolidated financial statements included in this Annual Report);
a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis (see Note 7 to our consolidated financial statements included in this Annual Report);
a loss of $22.7 million related to the termination of the development agreement, which included the carrying value of the development agreement asset that was written off (see Note 16 to our consolidated financial statements included in this Annual Report);
an impairment charge of $1.7 million to write down a loan receivable in June 2016 (see Note 13 to our consolidated financial statements included in this Annual Report); and
a loss of $9.5 million on the sales of certain assets, including the sale of Grassland (see Note 13 to our consolidated financial statements included in this Annual Report for a discussion of the sale of Grassland).

Revaluation of Liabilities.The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the year ended March 31, 2017. The increase in the expense during the year ended March 31, 2018 was due primarily to higher actual and expected production from new customers, resulting in an increase to the expected future royalty payment.


Liquids

The following table summarizes the operating results of our Liquids segment for the periods indicated:
  Year Ended March 31,  
  2018 2017 Change
  (in thousands, except per gallon amounts)
Propane sales:      
Revenues (1) $1,203,486
 $807,172
 $396,314
Cost of sales-excluding impact of derivatives 1,165,414
 772,871
 392,543
Cost of sales-derivative gain (5,577) (2,633) (2,944)
Product margin 43,649
 36,934
 6,715
       
Butane sales:      
Revenues (1) 562,066
 391,265
 170,801
Cost of sales-excluding impact of derivatives 535,017
 354,132
 180,885
Cost of sales-derivative loss 19,616
 7,863
 11,753
Product margin 7,433
 29,270
 (21,837)
       
Other product sales:      
Revenues (1) 432,570
 308,031
 124,539
Cost of sales-excluding impact of derivatives 414,980
 290,495
 124,485
Cost of sales-derivative gain (173) (1,477) 1,304
Product margin 17,763
 19,013
 (1,250)
       
Other revenues:      
Revenues (1) 22,548
 32,648
 (10,100)
Cost of sales 3,930
 12,893
 (8,963)
Product margin 18,618
 19,755
 (1,137)
       
Expenses:      
Operating expenses 32,792
 37,634
 (4,842)
General and administrative expenses 5,331
 4,831
 500
Depreciation and amortization expense 24,937
 19,163
 5,774
Loss on disposal or impairment of assets, net 117,516
 92
 117,424
Total expenses 180,576
 61,720
 118,856
Segment operating (loss) income $(93,113) $43,252
 $(136,365)
       
Liquids storage capacity - owned and leased (gallons) (2) 438,968
 358,537
 80,431
       
Propane sold (gallons) 1,361,173
 1,267,076
 94,097
Propane sold ($/gallon) $0.884
 $0.637
 $0.247
Cost per propane sold ($/gallon) $0.852
 $0.608
 $0.244
Propane product margin ($/gallon) $0.032
 $0.029
 $0.003
Propane inventory (gallons) (2) 48,928
 48,351
 577
Propane storage capacity leased to third parties (gallons) (2) 29,662
 33,495
 (3,833)
       
Butane sold (gallons) 544,750
 456,586
 88,164
Butane sold ($/gallon) $1.032
 $0.857
 $0.175
Cost per butane sold ($/gallon) $1.018
 $0.793
 $0.225
Butane product margin ($/gallon) $0.014
 $0.064
 $(0.050)
Butane inventory (gallons) (2) 15,385
 9,438
 5,947
Butane storage capacity leased to third parties (gallons) (2) 51,660
 80,346
 (28,686)
       
Other products sold (gallons) 400,405
 343,365
 57,040
Other products sold ($/gallon) $1.080
 $0.897
 $0.183
Cost per other products sold ($/gallon) $1.036
 $0.842
 $0.194
Other products product margin ($/gallon) $0.044
 $0.055
 $(0.011)
Other products inventory (gallons) (2) 5,822
 6,426
 (604)

(1)Revenues include $4.7 million and $1.9 million of intersegment sales during the years ended March 31, 2018 and 2017, respectively, that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2018 and March 31, 2017, respectively.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were due to higher commodity prices, and increased volume due to a new long-term marketing agreement.

Cost of Sales-Derivatives. Our cost of wholesale propane sales was reduced by $1.0 million and $1.5 million of net unrealized gains on derivatives for the years ended March 31, 2018 and 2017, respectively. Additionally, our cost of wholesale propane sales was reduced by $4.6 million and $1.1 million of net realized gains on derivatives for the years ended March 31, 2018 and 2017, respectively.

Product margins per gallon of propane sold were higher during the year ended March 31, 2018 than during the year ended March 31, 2017 facilitated by stronger winter demand.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were primarily due to higher commodity prices.

Cost of Sales-Derivatives. Our cost of butane sales was increased by $0.5 million and $2.0 million of net unrealized losses on derivatives for the years ended March 31, 2018 and 2017, respectively. Additionally, our cost of butane sales was increased by $19.1 million and $5.9 million of net realized losses on derivatives for the years ended March 31, 2018 and 2017, respectively.

Product margins per gallon of butane sold were lower during the year ended March 31, 2018 than during the year ended March 31, 2017 due primarily to the overall competitive nature of the market as well as higher than anticipated unrecovered railcar fleet costs.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were due primarily to a new long-term marketing agreement. Also, volumes have increased with the addition of the new Port Hudson terminal.

Cost of Sales-Derivatives. Our cost of sales of other products was reduced by $0.1 million and $0.2 million of net unrealized gains on derivatives for the years ended March 31, 2018 and 2017, respectively. Additionally, our cost of other products was reduced by $0.1 million and $1.3 million of net realized gains on derivatives for the years ended March 31, 2018 and 2017, respectively.

Product margin decrease during the year ended March 31, 2018 was due primarily to an increase in unrecovered railcar fleet costs.

Other Revenues. This revenue includes storage, terminaling and transportation services income. The decrease was due primarily to reduced transportation services and increased storage capacity available in the market.

Operating and General and Administrative Expenses. The decrease was due primarily to a reduction in incentive compensation that was paid in common units and reflected in “Corporate and Other”. Repair and maintenance expense was lower across most terminals due to tightly managing and prioritizing critical repairs.

Depreciation and Amortization Expense. The increase was due primarily to the acquisition of two liquids facilities during the previous fiscal year.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2018, we recorded a goodwill impairment charge of $116.9 million related to our salt dome storage facility in Utah due to the decreased demand for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods (see Note 6 to our consolidated financial statements included in this Annual Report). During the years ended March 31, 2018 and 2017, we recorded a net loss of $0.6 million and $0.1 million, respectively, related to the retirement of assets.


Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated.
  Year Ended March 31,  
  2018 2017 Change
  (in thousands, except per barrel amounts)
Refined products sales:      
Revenues (1) $11,827,222
 $8,884,976
 $2,942,246
Cost of sales-excluding impact of derivatives 11,709,786
 8,732,312
 2,977,474
Cost of sales-derivative loss 77,055
 43,358
 33,697
Product margin 40,381
 109,306
 (68,925)
       
Renewables sales:      
Revenues 373,669
 447,232
 (73,563)
Cost of sales-excluding impact of derivatives 362,457
 443,229
 (80,772)
Cost of sales-derivative loss 1,467
 1,291
 176
Product margin 9,745
 2,712
 7,033
       
Service fees and other revenues 300
 10,963
 (10,663)
       
Expenses:      
Operating expenses 14,057
 23,177
 (9,120)
General and administrative expenses 8,433
 9,821
 (1,388)
Depreciation and amortization expense 1,294
 1,562
 (268)
Gain on disposal or impairment of assets, net (30,098) (134,125) 104,027
Total income, net (6,314) (99,565) 93,251
Segment operating income $56,740
 $222,546
 $(165,806)
       
Gasoline sold (barrels) 108,427
 91,004
 17,423
Diesel sold (barrels) 56,020
 49,817
 6,203
Ethanol sold (barrels) 3,438
 4,605
 (1,167)
Biodiesel sold (barrels) 2,079
 2,413
 (334)
Refined products and renewables storage capacity - leased (barrels) (2) 9,911
 9,419
 492
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2) 1,068
 1,043
 25
Gasoline inventory (barrels) (2) 3,367
 2,993
 374
Diesel inventory (barrels) (2) 1,419
 1,464
 (45)
Ethanol inventory (barrels) (2) 701
 727
 (26)
Biodiesel inventory (barrels) (2) 261
 471
 (210)
Refined products sold ($/barrel) $71.921
 $63.094
 $8.827
Cost per refined products sold ($/barrel) $71.676
 $62.318
 $9.358
Refined products product margin ($/barrel) $0.245
 $0.776
 $(0.531)
Renewable products sold ($/barrel) $67.730
 $63.726
 $4.004
Cost per renewable products sold ($/barrel) $65.964
 $63.340
 $2.624
Renewable products product margin ($/barrel) $1.766
 $0.386
 $1.380
(1)
Revenues include $0.3 million and $0.5 millionof intersegment sales during the years ended March 31, 2018 and 2017, respectively, that are eliminated in our consolidated statements of operations.
(2)Information is presented as of March 31, 2018 and March 31, 2017, respectively.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were due to an increase in refined products prices and increased volumes. The increased volumes were due primarily to additional pipeline capacity rights purchased during the year ended March 31, 2017, an

expansion of our refined products operations and the continued demand for motor fuels. The decrease in margin was due primarily to negative impact of the continued decline in gasoline line space values on the Colonial Pipeline, discretionary terminal volume profitability and line space sales during the year ended March 31, 2018, compared to the year ended March 31, 2017. The average value of line space was approximately negative $0.007 per gallon for the year ended March 31, 2018, compared to an average value of approximately $0.009 per gallon for the year ended March 31, 2017.

Refined Products Cost of Sales-Derivatives. The margins for both the years ended March 31, 2018 and 2017 were negatively impacted by losses of $77.1 million and $43.4 million, respectively, from our risk management activities. These losses were due primarily to increasing future prices.

Renewables Revenues and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales-excluding impact of derivatives were due primarily to decreased volumes from the loss of a marketing contract with E Energy Adams, LLC in December 2017, partially offset by an increase in renewables prices. The margin was higher during the year ended March 31, 2018 due primarily to favorable biodiesel margins resulting from the biodiesel tax credit being reinstated in February 2018 for the 2017 calendar year.

Renewables Cost of Sales-Derivatives. The margins for both the years ended March 31, 2018 and 2017 were negatively impacted by losses of $1.5 million and $1.3 million, respectively, from our risk management activities. These losses were due primarily to the weakness in the price of renewable identification numbers and increasing future prices.

Service Fees and Other Revenues, Operating Expenses, General and Administrative Expenses. The decreases were due primarily to the expiration of a transition services agreement in October 2016 related to the sale of the general partner interest in TLP in February 2016 whereby we were reimbursed for certain expenses incurred on behalf of a third party.

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

Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2018, we recorded $30.1 million of the deferred gain from the sale of the general partner interest in TLP in February 2016 (see Note 15 to our consolidated financial statements included in this Annual Report for a further discussion). In addition, we recorded a net loss of less than $0.1 million on the disposal of certain assets.

During the year ended March 31, 2017, we recorded:

a $104.1 million gain from the sale of all of the TLP units we owned (see Note 16 to our consolidated financial statements included in this Annual Report for a further discussion);
$30.1 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 15 to our consolidated financial statements included in this Annual Report for a further discussion); and
a loss of $0.1 million on the sales of certain assets.


Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
  Year Ended March 31,  
  2018 2017 Change
  (in thousands)
Other revenues:      
Revenues $1,174
 $844
 $330
Cost of sales 530
 400
 130
Margin 644
 444
 200
      

Expenses: 
 

  
Operating expenses 1,173
 1,095
 78
General and administrative expenses 75,158
 82,723
 (7,565)
Depreciation and amortization expense 3,779
 3,612
 167
Loss (gain) on disposal or impairment of assets, net 8
 (1) 9
Total expenses 80,118
 87,429
 (7,311)
Operating loss $(79,474) $(86,985) $7,511

General and Administrative Expenses. The decrease for the year ended March 31, 2018 was due primarily to a decrease in equity-based compensation expense related to service awards. The expense related to service awards was $16.2 million for the year ended March 31, 2018, compared to $37.2 million for the year ended March 31, 2017. The increase in expense in the prior fiscal year was due to the cancellation of awards which accelerated the expense reporting. In addition, during the first quarter of the prior fiscal year, the expense for the service awards was accounted for under the liability method and due to an increase in our unit price during that period, we recorded an increase in equity-based compensation expense. Also, see Note 10 to our consolidated financial statements included in this Annual Report for a further discussion of our equity-based compensation. The decrease from equity-based compensation was partially offset by increases in legal expenses and workmen’s compensation.

Equity in Earnings of Unconsolidated Entities

The increase of $3.7 million during the year ended March 31, 2018 was due primarily to increased earnings related to our investment in Glass Mountain. On December 22, 2017, we sold our previously held 50% interest in Glass Mountain. See Note 16 to our consolidated financial statements included in this Annual Report for a further discussion.

Interest Expense

The increase of $49.2 million during the year ended March 31, 2018 was due primarily to the issuance of the 2023 Notes and 2025 Notes which have higher interest rates than the revolving credit facility. This was offset by lower interest expense on the revolving credit facility as our average balance outstanding decreased from $1.7 billion for the year ended March 31, 2017 to $1.0 billion for the year ended March 31, 2018.


(Loss) Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of (loss) gain on early extinguishment of liabilities, net for the periods indicated:
 Year Ended March 31,
 2018 2017
 (in thousands)
Early extinguishment of long-term debt (1)$(23,201) $6,922
Release of contingent consideration liabilities (2)
 22,278
Write-off deferred debt issuance costs (3)
 (4,473)
(Loss) gain on early extinguishment of liabilities, net$(23,201) $24,727
(1)During the year ended March 31, 2018, the net loss (inclusive of debt issuance costs written off) relates to the early extinguishment of all of the senior secured notes and a portion of the senior unsecured notes. During the year ended March 31, 2017, the net gain (inclusive of debt issuance costs written off) relates to the early extinguishment of a portion of the senior unsecured notes and certain equipment loans. See Note 8 to our consolidated financial statements included in this Annual Report for a further discussion.
(2)Relates to the release of certain contingent consideration liabilities in conjunction with the termination of the development agreement in June 2016 (see Note 16 to our consolidated financial statements included in this Annual Report for a further discussion). Also, during the year ended March 31, 2017, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain on the release of certain contingent consideration liabilities as the royalty agreement was terminated.
(3)Relates to the write off of certain deferred debt issuance costs in connection with the amendment and restatement of the Credit Agreement (as defined herein) (see Note 7 to our consolidated financial statements included in this Annual Report for a further discussion).

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 Year Ended March 31,
 2018 2017
 (in thousands)
Interest income (1)$6,297
 $7,553
Termination of storage sublease agreement (2)
 16,205
Other (3)656
 2,854
Other income, net$6,953
 $26,612
(1)During the year ended March 31, 2018, this relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility that is utilized by a third party and to a loan receivable from Victory Propane (see Note 13 to our consolidated financial statements included in this Annual Report for a further discussion). During the year ended March 31, 2017, this relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility that is utilized by a third party and to loan receivables from Victory Propane and Grassland (see Note 13 to our consolidated financial statements included in this Annual Report for a further discussion). On June 3, 2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on the receivable from Grassland has been eliminated in consolidation subsequent to that date.
(2)Represents a gain from the termination of a storage sublease agreement (see Note 16 to our consolidated financial statements included in this Annual Report for a further discussion).
(3)During the year ended March 31, 2018, this relates primarily to proceeds from a litigation settlement. During the year ended March 31, 2017, this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016, a gain on insurance settlement related to business interruption insurance coverage on a facility in our Water Solutions segment, a payment received related to a contract termination and another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.

Income Tax Expense

Income tax expense was $1.4 million during the year ended March 31, 2018, compared to income tax expense of $1.9 million during the year ended March 31, 2017. The decrease in income tax expense2021 was due primarily to a lower state franchise

79



certain assets we acquired in Mesquite acquisition in July 2019.
tax liability in Texas as well as a lower Canadian tax liability from our taxable corporate subsidiaries in Canada. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests - Redeemable and Non-redeemable

The decrease of $5.6 million during the year ended March 31, 2018 was due primarily to adjustments related to noncontrolling interests during the year ended March 31, 2017.

Non-GAAP Financial MeasuresSubsequent Events

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

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, revaluation of investments, 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 our Refined Products and Renewables segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss), (loss) income 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 our Refined Products and Renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record a realized gain or loss. We do not draw such a distinction between realized and unrealized gains and losses on derivatives of our Refined Products and Renewables segment. The primary hedging strategy of our Refined Products and Renewables segment is to hedge against the risk of declines in the value of inventory over the course of the contract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuation adjustment” row in the reconciliation table reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost, 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.


The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Net income (loss) $339,395
 $(69,605) $143,874
Less: Net loss (income) attributable to noncontrolling interests 20,206
 (240) (6,832)
Less: Net loss (income) attributable to redeemable noncontrolling interests 446
 (1,030) 
Net income (loss) attributable to NGL Energy Partners LP 360,047
 (70,875) 137,042
Interest expense 164,879
 199,747
 150,504
Income tax expense 2,222
 1,458
 1,939
Depreciation and amortization 224,547
 266,525
 238,583
EBITDA 751,695
 396,855
 528,068
Net unrealized (gains) losses on derivatives (17,296) 15,883
 (3,338)
Inventory valuation adjustment (1) (5,203) 11,033
 7,368
Lower of cost or market adjustments 2,695
 399
 (1,283)
Gain on disposal or impairment of assets, net (393,554) (105,313) (209,213)
Loss (gain) on early extinguishment of liabilities, net 12,340
 23,201
 (24,727)
Revaluation of investments 
 
 14,365
Equity-based compensation expense (2) 41,367
 35,241
 53,102
Acquisition expense (3) 9,780
 263
 1,771
Revaluation of liabilities (4) (5,373) 20,607
 12,761
Gavilon legal matter settlement (5) 34,788
 
 
Other (6) 9,203
 10,081
 2,443
Adjusted EBITDA $440,442
 $408,250
 $381,317
(1)Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost, 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.
(2)Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 10 to our consolidated financial statements included in this Annual Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 10 to our consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.
(3)Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions, including amounts accrued related to the LCT Capital, LLC legal matter (see Note 9 to our consolidated financial statements included in this Annual Report), partially offset by reimbursement for certain legal costs incurred in prior periods.
(4)Amounts represent the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.
(5)Represents the accrual for the estimated cost of the settlement of the Gavilon legal matter (see Note 9 to our consolidated financial statements included in this Annual Report). We have excluded this amount from Adjusted EBITDA as it relates to transactions that occurred prior to our acquisition of Gavilon LLC in December 2013.
(6)The amount for the year ended March 31, 2019 represents non-cash operating expenses related to our Grand Mesa Pipeline, unrealized losses on marketable securities and accretion expense for asset retirement obligations. The amount for the year ended March 31, 2018 represents non-cash operating expenses related to our Grand Mesa Pipeline, an adjustment to inventory related to prior periods and accretion expense for asset retirement obligations. The amount for the year ended March 31, 2017 represents non-cash operating expenses related to our Grand Mesa Pipeline and accretion expense for asset retirement obligations.


The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Reconciliation to consolidated statements of operations:      
Depreciation and amortization per EBITDA table $224,547
 $266,525
 $238,583
Intangible asset amortization recorded to cost of sales (5,619) (6,099) (6,828)
Depreciation and amortization of unconsolidated entities (331) (8,706) (11,869)
Depreciation and amortization attributable to noncontrolling interests 2,921
 497
 2,913
Depreciation and amortization attributable to discontinued operations (8,658) (43,197) (42,560)
Depreciation and amortization per consolidated statements of operations $212,860
 $209,020
 $180,239
       
Reconciliation to consolidated statements of cash flows:      
Depreciation and amortization per EBITDA table $224,547
 $266,525
 $238,583
Amortization of debt issuance costs recorded to interest expense 9,215
 10,619
 7,762
Depreciation and amortization of unconsolidated entities (331) (8,706) (11,869)
Depreciation and amortization attributable to noncontrolling interests 2,921
 497
 2,913
Depreciation and amortization attributable to discontinued operations (8,658) (43,197) (42,560)
Depreciation and amortization per consolidated statements of cash flows $227,694
 $225,738
 $194,829

The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements of operations for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Interest expense per EBITDA table $164,879
 $199,747
 $150,504
Interest expense attributable to unconsolidated entities (14) (149) 
Interest expense attributable to discontinued operations (139) (450) (510)
Interest expense per consolidated statements of operations $164,726
 $199,148
 $149,994

The following table summarizes additional amounts attributable to discontinued operations in the EBITDA table above for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Income tax expense $988
 $104
 $6
Net unrealized losses on derivatives $78
 $
 $47
Gain on disposal or impairment of assets, net $(408,964) $(89,290) $(295)


The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have revised certain prior period information to be consistent with the calculation method used in the current fiscal year.
  Year Ended March 31, 2019
  Crude Oil
Logistics
 Water
Solutions
 Liquids Refined
Products
and
Renewables
 Corporate
and
Other
 Discontinued Operations Consolidated
  (in thousands)
Operating (loss) income $(7,379) $210,525
 $(2,910) $27,459
 $(85,706) $
 $141,989
Depreciation and amortization 74,165
 108,162
 25,997
 1,518
 3,018
 
 212,860
Amortization recorded to cost of sales 80
 
 147
 5,392
 
 
 5,619
Net unrealized gains on derivatives (1,725) (15,521) (129) 
 
 
 (17,375)
Inventory valuation adjustment 
 
 
 (5,203) 
 
 (5,203)
Lower of cost or market adjustments 
 
 1,004
 1,691
 
 
 2,695
Loss (gain) on disposal or impairment of assets, net 107,424
 (138,204) 67,213
 (3,026) 889
 
 34,296
Equity-based compensation expense 
 
 
 
 41,367
 
 41,367
Acquisition expense 
 3,490
 161
 
 6,176
 
 9,827
Other income (expense), net 21
 (1) 68
 74
 (30,108) 
 (29,946)
Adjusted EBITDA attributable to unconsolidated entities 
 2,396
 6
 475
 
 
 2,877
Adjusted EBITDA attributable to noncontrolling interest 
 (166) (1,481) 
 
 
 (1,647)
Revaluation of liabilities 
 (5,373) 
 
 
 
 (5,373)
Gavilon legal matter settlement 
 
 
 
 34,788
 
 34,788
Other 8,274
 436
 66
 427
 
 
 9,203
Discontinued operations 
 
 
 
 
 4,465
 4,465
Adjusted EBITDA $180,860
 $165,744
 $90,142
 $28,807
 $(29,576) $4,465
 $440,442

  Year Ended March 31, 2018
  Crude Oil
Logistics
 Water
Solutions
 Liquids Refined
Products
and
Renewables
 Corporate
and
Other
 Discontinued Operations Consolidated
  (in thousands)
Operating income (loss) $122,904
 $(24,231) $(93,113) $56,740
 $(79,474) $
 $(17,174)
Depreciation and amortization 80,387
 98,623
 24,937
 1,294
 3,779
 
 209,020
Amortization recorded to cost of sales 338
 
 282
 5,479
 
 
 6,099
Net unrealized losses (gains) on derivatives 2,766
 13,694
 (577) 
 
 
 15,883
Inventory valuation adjustment 
 
 
 11,033
 
 
 11,033
Lower of cost or market adjustments 
 
 504
 (105) 
 
 399
(Gain) loss on disposal or impairment of assets, net (111,393) 6,863
 117,516
 (30,098) 8
 
 (17,104)
Equity-based compensation expense 
 
 
 
 35,241
 
 35,241
Acquisition expense 
 
 
 
 263
 
 263
Other income, net 535
 211
 105
 604
 5,498
 
 6,953
Adjusted EBITDA attributable to unconsolidated entities 11,507
 579
 
 4,308
 
 
 16,394
Adjusted EBITDA attributable to noncontrolling interest 
 (737) 
 
 
 
 (737)
Revaluation of liabilities 
 20,607
 
 
 
 
 20,607
Other 10,617
 461
 85
 
 
 
 11,163
Discontinued operations 
 
 
 
 
 110,210
 110,210
Adjusted EBITDA $117,661
 $116,070
 $49,739
 $49,255
 $(34,685) $110,210
 $408,250

  Year Ended March 31, 2017
  Crude Oil
Logistics
 Water
Solutions
 Liquids Refined
Products
and
Renewables
 Corporate
and
Other
 Discontinued Operations Consolidated
  (in thousands)
Operating (loss) income $(17,475) $44,587
 $43,252
 $222,546
 $(86,985) $
 $205,925
Depreciation and amortization 54,144
 101,758
 19,163
 1,562
 3,612
 
 180,239
Amortization recorded to cost of sales 384
 
 781
 5,663
 
 
 6,828
Net unrealized (gains) losses on derivatives (1,513) (2,088) 216
 
 
 
 (3,385)
Inventory valuation adjustment 
 
 
 7,368
 
 
 7,368
Lower of cost or market adjustments 
 
 
 (1,283) 
 
 (1,283)
Loss (gain) on disposal or impairment of assets, net 10,704
 (85,560) 92
 (134,125) (1) 
 (208,890)
Equity-based compensation expense 
 
 
 
 53,102
 
 53,102
Acquisition expense 
 
 
 
 1,771
 
 1,771
Other (expense) income, net (412) 739
 73
 19,263
 6,949
 
 26,612
Adjusted EBITDA attributable to unconsolidated entities 11,589
 106
 
 3,975
 
 
 15,670
Adjusted EBITDA attributable to noncontrolling interest 
 (9,210) 
 
 
 
 (9,210)
Revaluation of liabilities 
 12,761
 
 
 
 
 12,761
Other 1,996
 368
 79
 
 
 
 2,443
Discontinued operations 
 
 
 
 
 91,366
 91,366
Adjusted EBITDA $59,417
 $63,461
 $63,656
 $124,969
 $(21,552) $91,366
 $381,317

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations, borrowings under the Revolving Credit Facility and accessing capital markets. See Note 819 to our consolidated financial statements included in this Annual Report for a detailed descriptiondiscussion of transactions that occurred subsequent to March 31, 2022.

Segment Operating Results for the Years Ended March 31, 2022 and 2021

Water Solutions

The following table summarizes the operating results of our long-term debt. Our cash flows from operations are discussed below.Water Solutions segment for the periods indicated.

Year Ended March 31,
20222021Change
(in thousands, except per barrel and per day amounts)
Revenues:
Water disposal service fees$397,128 $308,511 $88,617 
Sale of recovered crude oil77,203 28,599 48,604 
Recycled water11,343 3,015 8,328 
Other revenues59,192 30,861 28,331 
Total revenues544,866 370,986 173,880 
Expenses:
Cost of sales-excluding impact of derivatives26,340 2,557 23,783 
Derivative loss7,640 7,065 575 
Operating expenses175,022 142,371 32,651 
General and administrative expenses7,352 6,403 949 
Depreciation and amortization expense214,558 222,107 (7,549)
Loss on disposal or impairment of assets, net25,598 76,942 (51,344)
Revaluation of liabilities(6,495)6,261 (12,756)
Total expenses450,015 463,706 (13,691)
Segment operating income (loss)$94,851 $(92,720)$187,571 
Produced water processed (barrels per day)
Delaware Basin1,531,830 1,148,582 383,248 
Eagle Ford Basin99,298 78,397 20,901 
DJ Basin142,611 111,016 31,595 
Other Basins24,179 26,596 (2,417)
Total1,797,918 1,364,591 433,327 
Recycled water (barrels per day)93,487 43,503 49,984 
Total (barrels per day)1,891,405 1,408,094 483,311 
Skim oil sold (barrels per day)2,864 1,957 907 
Service fees for produced water processed ($/barrel) (1)$0.61 $0.62 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (1)$0.12 $0.06 $0.06 
Operating expenses for produced water processed ($/barrel) (1)$0.27 $0.29 $(0.02)
Our borrowing needs vary
(1)    Total producedwater barrels processed during the yearyears ended March 31, 2022 and 2021 were 656,240,083 and 498,075,843, respectively.

Water Disposal Service Fee Revenues. The increase was due to an increase in partproduced 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 increased volumes from customers with long-term acreage dedications or minimum volume commitments 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 seasonal naturenumber of wells completed
56



in our Liquids and Refined Products and Renewables businesses. Our greatest working capital borrowing needs generally occurarea of operations during the period with increased flowback activity resulted in higher skim oil volumes per barrel of June through December, when we are buildingproduced water processed.

Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our natural gas liquids inventories in anticipation of the heating season as well as building our gasoline inventory in anticipation of the winter gasoline contango and blending season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our Liquids segment are the greatest and gasoline inventories needcustomers’ completion activities. The increase was due primarily to increasing demand for water to be minimized due to certain inventory requirements.

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

We believe that our anticipated cash flows from operations and the borrowing capacity under the Revolving Credit Facility are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital or sell assets. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs (see Part I, Item 1A–“Risk Factors”). Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.


We have made the strategic decision to completely exit the Retail Propane business and Bakken and South Pecos water disposal businesses and re-deploy proceeds from these sales to repay certain indebtedness and for certain near-term strategic growth opportunities,completion activity primarily in the Water Solutions segment. We believe our Water Solutions and Crude Oil Logistics businesses have organic growth opportunities with the activity in our core basins, including the Delaware Basin, and DJour customers transition from brackish non-potable water to recycled water.

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 in particular. We plan to pursue a strategy of growth through acquisitions as well as undertaking certain capital expansion projects.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. 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 consider financing future acquisitionsrecover when processing produced water and capital expansion projects through available capacityselling recovered skim oil. During the year ended March 31, 2022, we had $11.7 million of net unrealized losses on derivatives and $4.0 million of net realized gains on derivatives. During the Revolving Credit Facility or other formsyear ended March 31, 2021, we had $24.5 million of financing.net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. At March 31, 2022, we had approximately 3,000 barrels per day hedged for the next six months at an average price of $87.65 per barrel.

Other sourcesOperating and General and Administrative Expenses. The increase was due primarily to higher utility, royalty and chemical expenses as a result of liquiditythe 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. Going forward, the Partnership expects to see slight decreases in its operating expenses per barrel of produced water processed due to continued focus on cost maintenance and reductions 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 year ended March 31, 2019 are discussed below.2022 as well as certain other long-term assets being fully amortized or impaired during the years ended March 31, 2021 and 2022. These decreases were partially offset by the depreciation of newly developed facilities and infrastructure.

Dispositions

On May 3, 2018,Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2022, we sold our previously held 20% interest in E Energy Adams, LLC forrecorded a net proceedsloss of $18.6$29.8 million which we usedprimarily related to pay down amounts outstanding under the Revolving Credit Facility.

On July 10, 2018, we completedwrite-down of an inactive saltwater disposal facility and damaged equipment and wells at other facilities, abandonment of certain capital projects and the sale of virtually allcertain other miscellaneous assets and a gain of our remaining Retail Propane segment to Superior for total consideration of $889.8$4.3 million in cash. On August 14, 2018, we sold our previously held interest in Victory Propane. We used the proceeds to pay down amounts outstanding under the Revolving Credit Facility.

On November 30, 2018, we completedon the sale of NGL Water Solutions Bakken, LLCcertain land and a landfill permit.

During the year ended March 31, 2021, we recorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report);
an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
a net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $14.0 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17 to our consolidated financial statements included in this Annual Report).
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Revaluation of Liabilities. During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment. During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$2,432,393 $1,574,699 $857,694 
Crude oil transportation and other84,171 153,588 (69,417)
Total revenues (1)2,516,564 1,728,287 788,277 
Expenses:   
Cost of sales-excluding impact of derivatives2,271,973 1,473,330 798,643 
Derivative loss92,027 49,314 42,713 
Operating expenses54,606 56,918 (2,312)
General and administrative expenses7,537 8,038 (501)
Depreciation and amortization expense48,489 60,874 (12,385)
(Gain) loss on disposal or impairment of assets, net(3,101)384,143 (387,244)
Total expenses2,471,531 2,032,617 438,914 
Segment operating income (loss)$45,033 $(304,330)$349,363 
Crude oil sold (barrels)31,091 38,349 (7,258)
Crude oil transported on owned pipelines (barrels)28,410 32,797 (4,387)
Crude oil storage capacity - owned and leased (barrels) (2)5,232 5,239 (7)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 1,501 — 
Crude oil inventory (barrels) (2)1,339 1,201 138 
Crude oil sold ($/barrel)$78.235 $41.062 $37.173 
Cost per crude oil sold ($/barrel) (3)$73.075 $38.419 $34.656 
Crude oil product margin ($/barrel) (3)$5.160 $2.643 $2.517 
(1)    Revenues include $11.1 million and $6.7 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, respectively.
(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The increase was due primarily to an affiliate of Tallgrass Energy, LP for $85.0 millionincrease in net cash proceeds,crude oil prices during the year ended March 31, 2022, compared to the year ended March 31, 2021. This was offset by a reduction in sales volumes, primarily due to lower production in the DJ Basin. In addition, volumes also declined due to an increase in buy/sell transactions during the year ended March 31, 2022, compared to the year ended March 31, 2021. These are transactions in which we usedtransact to pay downpurchase 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 all 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 $72.6 million during the year ended March 31, 2022, compared to the year ended March 31, 2021. During the year ended March 31, 2022, physical volumes on the Grand Mesa Pipeline averaged approximately 78,000 barrels per day, compared to approximately 90,000 barrels per day for the year ended March 31, 2021 (volume amounts outstandingare 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.

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Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in crude oil prices during the year ended March 31, 2022, compared to the year ended March 31, 2021. The increase was partially offset by a reduction in volumes, as discussed above in “Crude Oil Sales Revenues.”

Derivative Loss. Our cost of sales during the year ended March 31, 2022 included $115.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $23.7 million of net unrealized gains on derivatives. The amounts for the year ended March 31, 2022 includes net realized losses of $83.5 million and unrealized gains of $45.0 million associated with derivative instruments related to our hedge of the CMA Differential Roll, defined and discussed below under “Non-GAAP Financial Measures.” Our cost of sales during the Revolving Credit Facility.year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives. Gains and losses from derivative activity should be offset by margin generated by the sale of the physical product.

On February 28, 2019,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 related to deficiency volumes from Extraction of $5.7 million during the year ended March 31, 2021. The decrease was offset by an increase in utility expenses due to Grand Mesa increased utility rates, as well as increased business insurance due to policy rate increases for the year ended March 31, 2022.

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.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2022, we completedrecorded a gain of $5.5 million on the sale of our South Pecos water disposal businesstrucking assets and a loss of $2.2 million due to damage caused by Hurricane Ida to one of our Gulf Coast terminals. During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a subsidiaryrejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report) and a net loss of WaterBridge Resources LLC$237.8 million for $232.2the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report).

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Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)$1,899,898 $1,124,087 $775,811 
Cost of sales-excluding impact of derivatives1,876,728 1,108,493 768,235 
Derivative loss2,907 930 1,977 
Product margin20,263 14,664 5,599 
Propane sales:
Revenues (1)1,325,941 1,027,582 298,359 
Cost of sales-excluding impact of derivatives1,313,765 949,402 364,363 
Derivative (gain) loss(20,519)10,994 (31,513)
Product margin32,695 67,186 (34,491)
Butane sales:
Revenues (1)863,348 517,857 345,491 
Cost of sales-excluding impact of derivatives794,180 469,394 324,786 
Derivative loss18,690 22,353 (3,663)
Product margin50,478 26,110 24,368 
Other product sales:
Revenues-excluding impact of derivatives (1)791,125 446,744 344,381 
Cost of sales-excluding impact of derivatives748,392 424,191 324,201 
Derivative loss (gain)15,812 (7,078)22,890 
Product margin26,921 29,631 (2,710)
Service revenues:
Revenues (1)16,200 33,915 (17,715)
Cost of sales1,404 4,751 (3,347)
Product margin14,796 29,164 (14,368)
Expenses:
Operating expenses55,907 55,273 634 
General and administrative expenses7,166 8,507 (1,341)
Depreciation and amortization expense18,714 29,184 (10,470)
Loss on disposal or impairment of assets, net71,807 3,350 68,457 
Total expenses153,594 96,314 57,280 
Segment operating (loss) income$(8,441)$70,441 $(78,882)
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Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3)156,219 427,975 (271,756)
Refined products sold (gallons)776,797 834,717 (57,920)
Refined products sold ($/gallon)$2.446 $1.347 $1.099 
Cost per refined products sold ($/gallon) (4)$2.416 $1.328 $1.088 
Refined products product margin ($/gallon) (4)$0.030 $0.019 $0.011 
Refined products inventory (gallons) (2)1,090 1,223 (133)
Propane sold (gallons)1,034,706 1,364,224 (329,518)
Propane sold ($/gallon)$1.281 $0.753 $0.528 
Cost per propane sold ($/gallon) (4)$1.270 $0.696 $0.574 
Propane product margin ($/gallon) (4)$0.011 $0.057 $(0.046)
Propane inventory (gallons) (2)37,719 51,026 (13,307)
Propane storage capacity leased to third parties (gallons) (2)(3)— 53,947 (53,947)
Butane sold (gallons)588,032 655,256 (67,224)
Butane sold ($/gallon)$1.468 $0.790 $0.678 
Cost per butane sold ($/gallon) (4)$1.351 $0.716 $0.635 
Butane product margin ($/gallon) (4)$0.117 $0.074 $0.043 
Butane inventory (gallons) (2)19,825 20,066 (241)
Butane storage capacity leased to third parties (gallons) (2)(3)— 56,700 (56,700)
Other products sold (gallons)376,906 471,245 (94,339)
Other products sold ($/gallon)$2.099 $0.948 $1.151 
Cost per other products sold ($/gallon) (4)$1.986 $0.900 $1.086 
Other products product margin ($/gallon) (4)$0.113 $0.048 $0.065 
Other products inventory (gallons) (2)18,614 19,195 (581)
(1)    Revenues include $1.3 million and $6.1 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in net cash proceeds,our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, respectively.
(3)    Decrease from March 31, 2021 relates to the sale of Sawtooth on June 18, 2021 (see Note 17 to our consolidated financial statements included in this Annual 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 prices. This was offset by a reduction in volumes sold due to tighter supply in the market. In certain markets in which we usedcompete, allocation of product from suppliers was reduced due to fundlower demand as a result of the COVID-19 pandemic. We are continuing to work to increase those allocations as demand for refined products increases.

Refined Products Derivative Loss. Our refined products margin during the year ended March 31, 2022 included a realized loss of $2.9 million and the year ended March 31, 2021 included a realized loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions.

Refined Products product margins per gallon of refined products sold for the year ended March 31, 2022 increased from the year ended March 31, 2021 primarily due to supply being short during the three months ended December 31, 2021, as a result of extended refinery downtime in certain markets in which we compete, and being well positioned during the extreme volatility surrounding global events occurring in the three months ended March 31, 2022.

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 domestic 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
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demand due to warmer than normal autumn temperatures, which resulted in lower product demand for crop drying, unusually warm weather during the early winter months and reduced volumes due to the loss of two producer services agreements.

Propane Derivative (Gain) Loss. Our wholesale propane cost of sales included $2.0 millionof net unrealized gains on derivatives and $18.5 million of net realized gains on derivatives during the year ended March 31, 2022. During the year ended March 31, 2021, our cost of wholesale propane sales included $3.3 million of net unrealized gains on derivatives and $14.3 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 winter season, along with increased competition in a number of markets where NGL purchases and sells propane. Midwestern demand was down year-over-year due to lower product demand for crop drying and warmer fall and winter weather. Our margin was also impacted by lower product allocation from certain suppliers and lower storage utilization due to decreased demand and the backwardated market structure.

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 year ended March 31, 2022 included $1.0 millionof net unrealized gains on derivatives and $19.7 million of net realized losses on derivatives. Our cost of butane sales included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives during the year ended March 31, 2021.

Butane product margins per gallon of butane sold were higher during year ended March 31, 2022 than during the year ended March 31, 2021 due primarily to a tight supply market, driven by an increase in demand for exports and an 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 and increased demand for biodiesel. This was partially offset by reduced natural gasoline volumes during the year ended March 31, 2022 as more production was being shipped via pipelines, reducing the availability for product to be shipped by railcars.

Other Products Derivatives Loss (Gain). Our derivatives of other products included $15.8 million of net realized losses on derivatives and there are no unrealized gains or losses on derivatives during the year ended March 31, 2022. Our derivatives of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives.

Other product sales product margins during the year ended March 31, 2022 increased due to an increase in demand for 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 a decline in margin for other natural gas liquids, as favorable supply contracts in the prior year and increased demand in certain markets during the prior year drove favorable sale differentials. Less volatility in the market, for both supply and demand, led to tighter margins for these products during the current period.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the year ended March 31, 2022 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 decrease was primarily due to the disposition of Sawtooth in June 2021 which was partially offset by increased travel as we came out of the pandemic.

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 year ended March 31, 2022, we recorded a net loss of $60.1 million related to the sale of Sawtooth (see Note 17 to our consolidated financial statements included in this Annual Report) 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 year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million due to the write down in value of a terminal we have ceased operating.
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Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Other revenues: 
Revenues$— $1,255 $(1,255)
Cost of sales— 1,816 (1,816)
Loss— (561)561 
Expenses: 
General and administrative expenses41,491 47,520 (6,029)
Depreciation and amortization expense6,959 5,062 1,897 
(Gain) loss on disposal or impairment of assets, net(50)11,001 (11,051)
Total expenses48,400 63,583 (15,183)
Operating loss$(48,400)$(64,144)$15,744 

General and Administrative Expenses. The decrease during the year ended March 31, 2022 was due primarily to lower compensation and legal expenses, offset by increased consulting fees. Compensation expense decreased due to lower equity-based compensation, partially 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.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily due to the write-off of a loan receivable related to the construction of a facility (see Note 17 to our consolidated financial statements included in this Annual Report).

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.4 million during the year ended March 31, 2022, compared to $1.9 million during the year ended March 31, 2021. The decrease of $0.5 million during the year ended March 31, 2022 was due primarily to lower earnings from certain membership interests related to specific land and water services operations.

Interest Expense

The following table summarizes the components of our consolidated interest expense for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Senior secured notes$153,750 $24,344 $129,406 
Senior unsecured notes87,766 96,711 (8,945)
Amortization of debt issuance costs16,960 13,420 3,540 
Revolving credit facility10,077 46,500 (36,423)
Other3,087 17,824 (14,737)
Total$271,640 $198,799 $72,841 

The increase of $72.8 million during the year ended March 31, 2022 was primarily due to the issuance of the 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) which resulted in us paying a higher interest rate on certain refinanced indebtedness. This increase was partially offset by the termination of the term credit agreement as well as the repurchases of a portion of our senior unsecured notes to mature in 2023 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report).

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Gain (Loss) on Early Extinguishment of Liabilities, Net

Gain on early extinguishment of liabilities, net was $1.8 million during the year ended March 31, 2022, compared to a loss on early extinguishment of liabilities, net of $16.7 million during the year ended March 31, 2021. During the years ended March 31, 2022 and 2021, the net gain (loss) (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 7 to our consolidated financial statements included in this Annual Report for a further discussion.

Other Income (Expense), Net

Other income, net was $2.3 million during the year ended March 31, 2022, compared to other expense, net of $36.5 million during the year ended March 31, 2021. The decrease in other expense, net of $38.8 million during the year ended March 31, 2022 was due primarily to a $40.0 million fee paid to the holders of the 9.00% Class D Preferred Units (“Class D Preferred Units”) during the year ended March 31, 2021 to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the $500.0 million asset-based revolving credit facility (“ABL Facility”) (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.

Income Tax (Expense) Benefit

Income tax expense was $1.0 million during the year ended March 31, 2022, compared to an income tax benefit of $3.4 million during the year ended March 31, 2021. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Noncontrolling interest income was $0.7 million during the year ended March 31, 2022, compared to $0.6 million during the year ended March 31, 2021. The increase of less than $0.1 million during the year ended March 31, 2022 was due primarily to higher income from certain recycling operations, partially offset by a higher loss from operations of the Sawtooth joint venture primarily due to the sale of Sawtooth in June 2021 and lower income from certain water solutions operations.


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Segment Operating Results for the Years Ended March 31, 2021 and 2020

Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated. As previously reported, on July 2, 2019, we acquired all of the assets of Mesquite and on October 31, 2019, we acquired all of the equity interests of Hillstone, thus the fiscal year 2020 results only include a partial year of operations related to these transactions.
 Year Ended March 31,
 20212020Change
 (in thousands, except per barrel and per day amounts)
Revenues:   
Water disposal service fees$308,511 $305,124 $3,387 
Sale of recovered crude oil28,599 59,445 (30,846)
Recycled water3,015 705 2,310 
Other revenues30,861 56,785 (25,924)
Total revenues370,986 422,059 (51,073)
Expenses:   
Cost of sales-excluding impact of derivatives2,557 5,511 (2,954)
Derivative loss (gain)7,065 (39,381)46,446 
Operating expenses142,371 192,987 (50,616)
General and administrative expenses6,403 7,939 (1,536)
Depreciation and amortization expense222,107 163,588 58,519 
Loss on disposal or impairment of assets, net76,942 255,285 (178,343)
Revaluation of liabilities6,261 9,194 (2,933)
Total expenses463,706 595,123 (131,417)
Segment operating loss$(92,720)$(173,064)$80,344 
Produced water processed (barrels per day)
Delaware Basin (1)1,148,582 1,170,158 (21,576)
Eagle Ford Basin78,397 246,784 (168,387)
DJ Basin111,016 164,936 (53,920)
Other Basins26,596 61,091 (34,495)
Total1,364,591 1,642,969 (278,378)
Recycled water (barrels per day)43,503 14,992 28,511 
Total (barrels per day)1,408,094 1,657,961 (249,867)
Skim oil sold (barrels per day)1,957 3,397 (1,440)
Service fees for produced water processed ($/barrel) (2)$0.62 $0.63 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (2)$0.06 $0.12 $(0.06)
Operating expenses for produced water processed ($/barrel) (2)$0.29 $0.40 $(0.11)
(1)    During the year ended March 31, 2020, barrels per day of producedwater processed by the assets acquired in the Mesquite and Hillstone transactions are calculated by the number of days in which we owned the assets.
(2)    Total producedwater barrels processed during the years ended March 31, 2021 and 2020 were 498,075,843 and 485,115,941, respectively.

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in the volume of produced water processed primarily driven by our acquisitions of Mesquite and Hillstone as well as new produced water volumes received upon the completion and commencement of the Partnership’s Poker Lake pipeline. The pipeline was successfully completed in October 2020 with a capacity of over 400,000 barrels per day and connects into our integrated Delaware Basin produced water pipeline infrastructure network. These increases were partially offset by a decrease in the volume of other produced water processed resulting from lower crude oil prices, development activity and production volumes.

Recovered Crude Oil Revenues. The decrease was due primarily to a reduction in the number of producing wells completed in our area of operations, a decrease in the percentage of skim oil volumes recovered per produced water barrel processed and lower crude oil prices. The lower percentage of skim oil volumes recovered was due primarily to an increase in
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produced water transported through pipelines (which contains less oil per barrel of produced water), and the addition of contract structures that allow producers to keep the skim oil recovered from produced water.

Recycled Water Revenues. The increase was due primarily to the timing of our customers completions driven by an increase in drilling and completion activity primarily in the Delaware Basin.

Other Revenues. The decrease was due primarily to reduced customer development activity and needs for these services resulting from the decline in crude oil prices.

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to lower purchasing and transportation costs related to our brackish non-potable water and crude oil sales.

Derivative Loss (Gain). During the year ended March 31, 2021, we had $24.5 million of net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. During the year ended March 31, 2020, we had $29.9 million of net unrealized gains on derivatives and $9.5 million of net realized gains on derivatives. In June 2019, we settled derivative contracts that had scheduled settlement dates from April through December 2020 and recorded a gain of $1.9 million on those derivatives.

Operating and General and Administrative Expenses. The decrease was due primarily to the deployment of automation and subsequent reduction in employee headcount, reduced equipment rental (including generators) and associated diesel fuel and repairs and lower maintenance expense. In addition, acquisition expenses were lower by $4.1 million as we did not close on any acquisitions during the year ended March 31, 2021.

Depreciation and Amortization Expense.The increase was due primarily to Mesquite and Hillstone acquisitions completed in the prior year and newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report);
an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
a net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $14.0 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17 to our consolidated financial statements included in this Annual Report).

During the year ended March 31, 2020, we recorded:

a goodwill impairment charge of $250.0 million related to the current macroeconomic conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, resulting in expected decreases in future cash flows for certain of our assets (see Note 5 to our consolidated financial statements included in this Annual Report);
an impairment charge of $13.5 million related to certain inactive saltwater disposal facilities;
a net loss of $9.2 million on the disposals of certain other assets;
a gain of $14.5 million for the sale of certain water permits (see Note 17 to our consolidated financial statements included in this Annual Report); and
a gain of $1.0 million for cash received related to a loan receivable that was previously written off.

Revaluation of Liabilities. During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.
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During the year ended March 31, 2020, a portion of the revaluation of liabilities represented the change in the valuation of our contingent consideration liability issued by us as part of a business combination. Under the agreement, we were required to make additional payments to the seller based on the volume of produced water processed by the assets acquired. During the year ended March 31, 2020, the thresholds for the volume of produced water processed were surpassed, thus triggering our obligation to pay the seller.

During the year ended March 31, 2020, there was a reduction in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers and an increase in facilities due to acquisitions, resulting in a decrease to the expected future royalty payment.

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$1,574,699 $2,383,812 $(809,113)
Crude oil transportation and other153,588 184,129 (30,541)
Total revenues (1)1,728,287 2,567,941 (839,654)
Expenses:   
Cost of sales-excluding impact of derivatives1,473,330 2,347,863 (874,533)
Derivative loss (gain)49,314 (35,736)85,050 
Operating expenses56,918 61,708 (4,790)
General and administrative expenses8,038 6,723 1,315 
Depreciation and amortization expense60,874 70,759 (9,885)
Loss (gain) on disposal or impairment of assets, net384,143 (1,144)385,287 
Total expenses2,032,617 2,450,173 (417,556)
Segment operating (loss) income$(304,330)$117,768 $(422,098)
Crude oil sold (barrels)38,349 42,799 (4,450)
Crude oil transported on owned pipelines (barrels)32,797 45,884 (13,087)
Crude oil storage capacity - owned and leased (barrels) (2)5,239 5,362 (123)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 2,062 (561)
Crude oil inventory (barrels) (2)1,201 1,111 90 
Crude oil sold ($/barrel)$41.062 $55.698 $(14.636)
Cost per crude oil sold ($/barrel) (3)$38.419 $54.858 $(16.439)
Crude oil product margin ($/barrel) (3)$2.643 $0.840 $1.803 
(1)    Revenues include $6.7 million and $18.2 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The decrease was due primarily to a decrease in crude oil prices and sales volumes during the year ended March 31, 2021, compared to the year ended March 31, 2020. The volumes decreased due to changes in the method of delivery to the market in the Permian region, as a significant amount of production switched to long haul pipeline owned and controlled by others.

Crude Oil Transportation and Other Revenues. The decrease was primarily due to our Grand Mesa Pipeline, which decreased revenues by $32.8 million during the year ended March 31, 2021, compared to the year ended March 31, 2020. During the year ended March 31, 2021, financial volumes on the Grand Mesa Pipeline averaged approximately 94,000 barrels per day, compared to 131,000 barrels per day for the year ended March 31, 2020 (volume amounts are from both internal and
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external parties) primarily due to the court approved rejection of the Extraction transportation agreement (see Note 17 to our consolidated financial statements included in this Annual Report).

Cost of Sales-Excluding Impact of Derivatives. The decrease was due to a decrease in crude oil prices and reduced volumes during the year ended March 31, 2021, compared to the year ended March 31, 2020.

Derivative Loss (Gain). Our cost of sales during the year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives. The losses are due to a very volatile pricing market during the year ended March 31, 2021. Our cost of sales during the year ended March 31, 2020 included $24.4 million of net realized gains on derivatives and $11.3 million of net unrealized gains on derivatives. In March 2020, we closed realized derivative contracts that had scheduled settlement dates from May 2020 through June 2020, which accounted for $16.7 million of the realized gains for the prior year.

Crude Oil Product Margin. The increase was due to inventory purchased during the three months ended June 30, 2020 at lower prices and held for sale during the three months ended September 30, 2020 and the three months ended December 31, 2020 when prices recovered.

Operating and General and Administrative Expenses.Expenses decreased compared to the prior year due to a decrease of utilities, as lower volumes were being shipped on the Grand Mesa Pipeline and other cost cutting measures which were partially offset by the write off of a $5.7 million receivable from Extraction (see Note 17 to our consolidated financial statements included in this Annual Report).

Depreciation and Amortization Expense. The decrease was due to the retirement of certain assets and other assets being fully depreciated or amortized during the year ended March 31, 2020.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report), and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report). During the year ended March 31, 2020, we recorded a net gain of $1.1 million related to the disposal of certain assets.



















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Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)(2)$1,124,087 $2,394,663 $(1,270,576)
Cost of sales-excluding impact of derivatives (3)1,108,493 2,367,850 (1,259,357)
Derivative loss (gain)930 (3,225)4,155 
Product margin14,664 30,038 (15,374)
Propane sales:
Revenues (1)1,027,582 846,756 180,826 
Cost of sales-excluding impact of derivatives949,402 766,521 182,881 
Derivative loss10,994 3,536 7,458 
Product margin67,186 76,699 (9,513)
Butane sales:
Revenues (1)517,857 564,016 (46,159)
Cost of sales-excluding impact of derivatives469,394 486,777 (17,383)
Derivative loss (gain)22,353 (8,288)30,641 
Product margin26,110 85,527 (59,417)
Other product sales:
Revenues-excluding impact of derivatives (1)446,744 775,458 (328,714)
Cost of sales-excluding impact of derivatives424,191 732,967 (308,776)
Derivative gain(7,078)(2,846)(4,232)
Product margin29,631 45,337 (15,706)
Service revenues:
Revenues (1)33,915 40,216 (6,301)
Cost of sales4,751 9,207 (4,456)
Product margin29,164 31,009 (1,845)
Expenses:
Operating expenses55,273 77,980 (22,707)
General and administrative expenses8,507 12,644 (4,137)
Depreciation and amortization expense29,184 27,930 1,254 
Loss on disposal or impairment of assets, net3,350 7,645 (4,295)
Total expenses96,314 126,199 (29,885)
Segment operating income$70,441 $142,411 $(71,970)
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Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (4)427,975 400,301 27,674 
Refined products sold (gallons)834,717 1,272,546 (437,829)
Refined products sold ($/gallon)$1.347 $1.890 $(0.543)
Cost per refined products sold ($/gallon) (5)$1.328 $1.861 $(0.533)
Refined products product margin ($/gallon) (5)$0.019 $0.029 $(0.010)
Refined products inventory (gallons) (4)1,223 2,391 (1,168)
Propane sold (gallons)1,364,224 1,478,759 (114,535)
Propane sold ($/gallon)$0.753 $0.573 $0.180 
Cost per propane sold ($/gallon) (5)$0.696 $0.518 $0.178 
Propane product margin ($/gallon) (5)$0.057 $0.055 $0.002 
Propane inventory (gallons) (4)51,026 57,221 (6,195)
Propane storage capacity leased to third parties (gallons) (4)53,947 46,066 7,881 
Butane sold (gallons)655,256 814,528 (159,272)
Butane sold ($/gallon)$0.790 $0.692 $0.098 
Cost per butane sold ($/gallon) (5)$0.716 $0.598 $0.118 
Butane product margin ($/gallon) (5)$0.074 $0.094 $(0.020)
Butane inventory (gallons) (4)20,066 24,808 (4,742)
Butane storage capacity leased to third parties (gallons) (4)56,700 33,894 22,806 
Other products sold (gallons)471,245 602,872 (131,627)
Other products sold ($/gallon)$0.948 $1.286 $(0.338)
Cost per other products sold ($/gallon) (5)$0.900 $1.216 $(0.316)
Other products product margin ($/gallon) (5)$0.048 $0.070 $(0.022)
Other products inventory (gallons) (4)19,195 26,126 (6,931)
(1)    Revenues include $6.1 million and $5.0 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Revenues include $10.3 million of intersegment sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(3)    Cost of sales include $8.2 million of intersegment cost of sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(4)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(5)    Cost and product margin per gallon excludes the impact of derivatives.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales, excluding the impact of derivatives, were due to a decrease in refined products prices and volumes due to the sizable reduction in demand for both gasoline and diesel products due to the COVID-19 pandemic. There was also a large decrease in volumes due to the elimination of our sales in the Northeast and Southeast due to our non-compete clause with the purchaser of our TPSL business.

Refined Products Derivative Loss (Gain). Our margin during the year ended March 31, 2021 included a loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions. Our margin during the year ended March 31, 2020 included a gain of $3.2 million from our risk management activities due primarily to unrealized gains on our open forward physical positions and decreases in NYMEX futures prices on our short future positions.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were due to increased commodity prices in the fourth quarter of the year ended March 31, 2021, as a result of winter storm Uri in February 2021. These increases were partially offset by lower volumes as a result of lower commercial and industrial demand due to the COVID-19 pandemic.
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Propane Derivative Loss. Our cost of wholesale propane sales included $3.3 million of net unrealized gains on derivatives and $14.3 million of net realized losses on derivatives during the year ended March 31, 2021. During the year ended March 31, 2020, our cost of wholesale propane sales included $1.5 million of net unrealized losses on derivatives and $2.0 million of net realized losses on derivatives.

Propane product margins per gallon of propane sold were higher during the year ended March 31, 2021 than during the year ended March 31, 2020 due primarily to inventory values aligning with reduced commodity prices at index markets as well as the extreme cold weather in February 2021.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales-excluding impact of derivatives in butane were due primarily to lower product demand which decreased due to lower gasoline blending volumes and decreased export sales related to the COVID-19 pandemic.

Butane Derivative Loss (Gain). Our cost of butane sales during the year ended March 31, 2021 included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives. Our cost of butane sales included $0.5 million of net unrealized losses on derivatives and $8.8 million of net realized gains on derivatives during the year ended March 31, 2020.

Butane product margins per gallon of butane sold were lower during the year ended March 31, 2021 than during the year ended March 31, 2020 due primarily to the weaker domestic market demand due to COVID-19.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales - excluding the impact of derivatives, were due to lower commodity prices and lower demand due to the lockdowns related to the COVID-19 pandemic.

Other Products Derivative Gain. Our cost of sales of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives. Our cost of sales of other products included $0.6 million of net unrealized losses on derivatives and $3.4 million of net realized gains on derivatives during the year ended March 31, 2020.

Other product sales product margins during the year ended March 31, 2021 decreased primarily due to softer product demand during the COVID-19 pandemic and associated economic slowdown. In addition, the margin for the year ended March 31, 2020, included a biodiesel tax credit of $13.8 million. The impact of the biodiesel tax credit for the year March 31, 2021 was approximately $0.4 million.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the year ended March 31, 2021 was primarily to weaker demand as producers shut-in and curtailed production.

Operating and General and Administrative Expenses. Expenses decreased for the year ended March 31, 2021 due to lower volumes and services rendered as well as reduced costs with lower incentive compensation and restricted travel due to COVID-19.

Depreciation and Amortization Expense. Expense for the year ended March 31, 2021 was higher due to the acceleration of depreciation expense prior to the sale of a terminal facility.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million to the write down in value of a terminal we have ceased operating. During the year ended March 31, 2020, we recorded an impairment of $7.7 million due to adjusting the cost basis of pipeline linefill to the market price of propane as of March 31, 2020.

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Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Other revenues: 
Revenues$1,255 $1,038 $217 
Cost of sales1,816 1,774 42 
Loss(561)(736)175 
Expenses: 
Operating expenses— 318 (318)
General and administrative expenses47,520 86,358 (38,838)
Depreciation and amortization expense5,062 3,035 2,027 
Loss on disposal or impairment of assets, net11,001 — 11,001 
Total expenses63,583 89,711 (26,128)
Operating loss$(64,144)$(90,447)$26,303 

General and Administrative Expenses. The decrease during the year ended March 31, 2021 was due primarily to lower equity-based compensation expense and acquisition expenses. During the year ended March 31, 2021, equity-based compensation expense was $6.7 million, compared to $26.5 million during the year ended March 31, 2020. During the year ended March 31, 2021, acquisition expenses were $1.7 million, compared to $15.6 million during the year ended March 31, 2020. The driver behind the decrease in acquisition expenses was primarily due to expenses incurred in connection with our acquisitions of both Mesquite and Hillstone in the year ended March 31, 2020.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily due to the write-off of a loan receivable made to a third party for the construction of a natural gas liquids terminal businessloading/unloading facility (see Note 17 to our consolidated financial statements included in this Annual Report ) and a loss from the write-off of installment payments made in connection with an option agreement to invest in a third party.

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.9 million during the remaining proceeds usedyear ended March 31, 2021, compared to $1.3 million during the year ended March 31, 2020. The increase of $0.6 million during the year ended March 31, 2021 was due primarily to higher earnings from certain membership interests acquired in November 2019 related to specific land and water services operations, partially fundoffset by a higher loss from our interest in an aircraft company during the redemptionyear ended March 31, 2021.

Interest Expense

The following table summarizes the components of our 2019consolidated interest expense for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Senior unsecured notes$96,711 $102,289 $(5,578)
Revolving credit facility46,500 57,470 (10,970)
Senior secured notes24,344 — 24,344 
Amortization of debt issuance costs13,420 10,901 2,519 
Other17,824 10,524 7,300 
Total$198,799 $181,184 $17,615 

The increase of $17.6 million during the year ended March 31, 2021 was due to the issuance of the 2026 Senior Secured Notes. This increase was offset by repurchases of a portion of our senior unsecured notes to mature in 2023, 2025 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report).
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(Loss) Gain on Early Extinguishment of Liabilities, Net

Loss on early extinguishment of liabilities, net was $16.7 million during the year ended March 31, 2021, compared to a gain on early extinguishment of liabilities, net of $1.3 million during the year ended March 31, 2020. During the years ended March 31, 2021 and 2020, the net (loss) gain (inclusive of debt issuance costs written off) relates to the early extinguishment of a portion of the outstanding senior unsecured notes. See Note 7 to our consolidated financial statements included in this Annual Report for a further discussion.

Other (Expense) Income, Net

Other expense, net was $36.5 million during the year ended March 31, 2021, compared to other income, net of $1.7 million during the year ended March 31, 2020. The increase in other expense, net of $38.2 million during the year ended March 31, 2021 was due primarily to a $40.0 million fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.

Income Tax Benefit (Expense)

Income tax benefit was $3.4 million during the year ended March 31, 2021, compared to income tax expense of $0.3 million during the year ended March 31, 2020. The increase in the income tax benefit during the year ended March 31, 2021 was primarily due to a full year of Hillstone operations during the year ended March 31, 2021 compared to five months of Hillstone operations during the year ended March 31, 2020. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests

Noncontrolling interest income was $0.6 million during the year ended March 31, 2021, compared to a noncontrolling interest loss of $1.8 million during the year ended March 31, 2020. The increase in noncontrolling interest income of $2.4 million during the year ended March 31, 2021 was due primarily to a lower loss from operations from certain water operations, income from operations from the Sawtooth joint venture and higher income from operations of certain assets we acquired in Mesquite acquisition in July 2019.

Subsequent Events

See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of transactions that occurred subsequent to March 31, 2019.2022.


Long-Term Debt

Credit Agreement

We are party to a $1.765 billion credit agreement (the “Credit Agreement”) with a syndicate of banks. As ofSegment Operating Results for the Years Ended March 31, 2019,2022 and 2021

Water Solutions

The following table summarizes the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacityoperating results of $1.250 billionour Water Solutions segment for cash borrowings and letters of credit (the “Working Capital Facility”), and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $515.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility,periods indicated.
Year Ended March 31,
20222021Change
(in thousands, except per barrel and per day amounts)
Revenues:
Water disposal service fees$397,128 $308,511 $88,617 
Sale of recovered crude oil77,203 28,599 48,604 
Recycled water11,343 3,015 8,328 
Other revenues59,192 30,861 28,331 
Total revenues544,866 370,986 173,880 
Expenses:
Cost of sales-excluding impact of derivatives26,340 2,557 23,783 
Derivative loss7,640 7,065 575 
Operating expenses175,022 142,371 32,651 
General and administrative expenses7,352 6,403 949 
Depreciation and amortization expense214,558 222,107 (7,549)
Loss on disposal or impairment of assets, net25,598 76,942 (51,344)
Revaluation of liabilities(6,495)6,261 (12,756)
Total expenses450,015 463,706 (13,691)
Segment operating income (loss)$94,851 $(92,720)$187,571 
Produced water processed (barrels per day)
Delaware Basin1,531,830 1,148,582 383,248 
Eagle Ford Basin99,298 78,397 20,901 
DJ Basin142,611 111,016 31,595 
Other Basins24,179 26,596 (2,417)
Total1,797,918 1,364,591 433,327 
Recycled water (barrels per day)93,487 43,503 49,984 
Total (barrels per day)1,891,405 1,408,094 483,311 
Skim oil sold (barrels per day)2,864 1,957 907 
Service fees for produced water processed ($/barrel) (1)$0.61 $0.62 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (1)$0.12 $0.06 $0.06 
Operating expenses for produced water processed ($/barrel) (1)$0.27 $0.29 $(0.02)
(1)    Total producedwater barrels processed during the “Revolving Credit Facility”). The Revolving Credit Facility allows us to reallocate amounts between the Expansion Capital Facility and Working Capital Facility. We had letters of credit of $143.4 million on the Working Capital Facility atyears ended March 31, 2019.2022 and 2021 were 656,240,083 and 498,075,843, respectively.

Water Disposal Service Fee Revenues. The commitments under the Credit Agreement expire on October 5, 2021.

On February 6, 2019, we amended the Credit Agreement,increase was due to among other things, reset the basket for the repurchasean increase in produced water volumes processed as a result of common units with a limit of $150 million in aggregate during the remaining term of the Credit Agreement, not to exceed $50 million per fiscal quarter, so long as, both immediately beforeincreased crude oil production driven by higher crude oil prices and after giving pro forma effect to the repurchases, the Partnership’s Leverage Ratio (as definedcompletion activity, primarily in the Credit Agreement) is less than 3.25x and Revolving Availability (also as defined in the Credit Agreement) is greater thanDelaware Basin. This was partially offset by lower service fees received per barrel due to increased volumes from customers with long-term acreage dedications or equalminimum volume commitments with lower contracted fees.

Recovered Crude Oil Revenues. The increase was due primarily to $200 million. In addition, the amendment decreases the Maximum Total Leverage Indebtedness Ratio beginning September 30, 2019 with a further decrease beginning March 31, 2020, and amends the defined term “Consolidated EBITDA”higher volumes of skim oil sold due to exclude the “Gavilon Energy EPA Settlement” (as defined in the Credit Agreement) solely for the two quarters ending December 31, 2018 and March 31, 2019.

We were in compliance with the covenants under the Credit Agreement at March 31, 2019.


Senior Unsecured Notes

The senior unsecured notes include, as defined below, the 2019 Notes, 2021 Notes, 2023 Notes, 2025 Notes and 2026 Notes (collectively, the “Senior Unsecured Notes”).

Issuances

On October 24, 2016, we issued $700.0 million of 7.50% Senior Unsecured Notes Due 2023 (the “2023 Notes”). Interest is payable on May 1 and November 1 of each year. The 2023 Notes mature on November 1, 2023.

On February 22, 2017, we issued $500.0 million of 6.125% Senior Unsecured Notes Due 2025 (the “2025 Notes”). Interest is payable on March 1 and September 1 of each year. The 2025 Notes mature on March 1, 2025.

On April 9, 2019, we issued $450.0 million of 7.50% Senior Unsecured Notes Due 2026 (the “2026 Notes”) in a private placement. Interest is payable on April 15 and October 15 of each year, beginning on October 15, 2019. We received net proceeds of $441.8 million, after the initial purchasers’ discount of $6.8 million and offering costs of $1.5 million. The 2026 Notes mature on April 15, 2026.

Redemptions and Repurchases

On October 16, 2018, we redeemed all of the remaining outstanding 6.875% Senior Unsecured Notes Due 2021 (“2021 Notes”). On March 15, 2019, we redeemed all of the remaining outstanding 5.125% Senior Unsecured Notes Due 2019 (“2019 Notes”). We used amounts available under the Revolving Credit Facility to fund the redemptionsincreased produced water processed as well as proceedshigher crude oil prices realized. Additionally, an increase in the number of wells completed
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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. Revenue from recycled water includes the sale of produced water and recycled water for use in our South Pecoscustomers’ completion activities. The increase was due primarily to increasing demand for water disposal businessto be used in February 2019.

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.

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, 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. 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 produced water and selling recovered skim oil. During the year ended March 31, 2019, 2022, we repurchased $25.4had $11.7 million of the 2019 Notesnet unrealized losses on derivatives and $8.6$4.0 million of net realized gains on derivatives. During the 2023 Notes.

Compliance

year ended March 31, 2021, we had $24.5 million of net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. At March 31, 2019,2022, we were in compliance withhad approximately 3,000 barrels per day hedged for the covenants under allnext six months at an average price of $87.65 per barrel.

Operating and General and Administrative Expenses. The increase was due primarily to higher utility, royalty and chemical expenses as a result of the Senior Unsecured Notes indentures.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. Going forward, the Partnership expects to see slight decreases in its operating expenses per barrel of produced water processed due to continued focus on cost maintenance and reductions and an increase in overall disposal volumes.

ForDepreciation 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 year ended March 31, 2022 as well as certain other long-term assets being fully amortized or impaired during the years ended March 31, 2021 and 2022. These decreases were partially offset by the depreciation of newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2022, we recorded a further discussionnet loss of $29.8 million primarily related to the Revolving Credit Facilitywrite-down of an inactive saltwater disposal facility and Senior Unsecured Notes redemptionsdamaged equipment and repurchases, see 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 year ended March 31, 2021, we recorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 84 and Note 6 to our consolidated financial statements included in this Annual Report.Report);

an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
Revolving Credit Facility Borrowingsa net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $14.0 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17 to our consolidated financial statements included in this Annual Report).
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Revaluation of Liabilities. During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment. During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.

Crude Oil Logistics

The following table summarizes the Revolving Credit Facility borrowingsoperating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$2,432,393 $1,574,699 $857,694 
Crude oil transportation and other84,171 153,588 (69,417)
Total revenues (1)2,516,564 1,728,287 788,277 
Expenses:   
Cost of sales-excluding impact of derivatives2,271,973 1,473,330 798,643 
Derivative loss92,027 49,314 42,713 
Operating expenses54,606 56,918 (2,312)
General and administrative expenses7,537 8,038 (501)
Depreciation and amortization expense48,489 60,874 (12,385)
(Gain) loss on disposal or impairment of assets, net(3,101)384,143 (387,244)
Total expenses2,471,531 2,032,617 438,914 
Segment operating income (loss)$45,033 $(304,330)$349,363 
Crude oil sold (barrels)31,091 38,349 (7,258)
Crude oil transported on owned pipelines (barrels)28,410 32,797 (4,387)
Crude oil storage capacity - owned and leased (barrels) (2)5,232 5,239 (7)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 1,501 — 
Crude oil inventory (barrels) (2)1,339 1,201 138 
Crude oil sold ($/barrel)$78.235 $41.062 $37.173 
Cost per crude oil sold ($/barrel) (3)$73.075 $38.419 $34.656 
Crude oil product margin ($/barrel) (3)$5.160 $2.643 $2.517 
  
Average Balance
Outstanding
 
Lowest
Balance
 
Highest
Balance
  (in thousands)
Year Ended March 31, 2019      
Expansion capital borrowings $82,816
 $
 $330,000
Working capital borrowings $852,552
 $439,000
 $1,095,500
Year Ended March 31, 2018      
Expansion capital borrowings $167,900
 $
 $397,000
Working capital borrowings $837,651
 $719,500
 $1,014,500

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue(1)    Revenues include $11.1 million and sell up to $200.0$6.7 million of common units. Weintersegment sales during the years ended March 31, 2022 and 2021, respectively, that are under no obligationeliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, respectively.
(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The increase was due primarily to issue equity under the ATM Program. We did not sell any common units under the ATM Programan increase in crude oil prices during the year ended March 31, 2022, compared to the year ended March 31, 2021. This was offset by a reduction in sales volumes, primarily due to lower production in the DJ Basin. In addition, volumes also declined due to an increase in buy/sell transactions during the year ended March 31, 2022, compared to the year ended March 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 all 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 $72.6 million during the year ended March 31, 2022, compared to the year ended March 31, 2021. During the year ended March 31, 2022, physical volumes on the Grand Mesa Pipeline averaged approximately 78,000 barrels per day, compared to approximately 90,000 barrels per day for the year ended March 31, 2021 (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.

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Cost of Sales-Excluding Impact of Derivatives. The increase was due primarily to an increase in crude oil prices during the year ended March 31, 2022, compared to the year ended March 31, 2021. The increase was partially offset by a reduction in volumes, as discussed above in “Crude Oil Sales Revenues.”

Derivative Loss. Our cost of sales during the year ended March 31, 2022 included $115.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $23.7 million of net unrealized gains on derivatives. The amounts for the year ended March 31, 2022 includes net realized losses of $83.5 million and unrealized gains of $45.0 million associated with derivative instruments related to our hedge of the CMA Differential Roll, defined and discussed below under “Non-GAAP Financial Measures.” Our cost of sales during the year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives. Gains and losses from derivative activity should be offset by margin generated by the sale of the physical product.

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 related to deficiency volumes from Extraction of $5.7 million during the year ended March 31, 2021. The decrease was offset by an increase in utility expenses due to Grand Mesa increased utility rates, as well as increased business insurance due to policy rate increases for the year ended March 31, 2022.

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.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2022, we recorded a gain of $5.5 million on the sale of our trucking assets and a loss of $2.2 million due to damage caused by Hurricane Ida to one of our Gulf Coast terminals. During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report) and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report).

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Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)$1,899,898 $1,124,087 $775,811 
Cost of sales-excluding impact of derivatives1,876,728 1,108,493 768,235 
Derivative loss2,907 930 1,977 
Product margin20,263 14,664 5,599 
Propane sales:
Revenues (1)1,325,941 1,027,582 298,359 
Cost of sales-excluding impact of derivatives1,313,765 949,402 364,363 
Derivative (gain) loss(20,519)10,994 (31,513)
Product margin32,695 67,186 (34,491)
Butane sales:
Revenues (1)863,348 517,857 345,491 
Cost of sales-excluding impact of derivatives794,180 469,394 324,786 
Derivative loss18,690 22,353 (3,663)
Product margin50,478 26,110 24,368 
Other product sales:
Revenues-excluding impact of derivatives (1)791,125 446,744 344,381 
Cost of sales-excluding impact of derivatives748,392 424,191 324,201 
Derivative loss (gain)15,812 (7,078)22,890 
Product margin26,921 29,631 (2,710)
Service revenues:
Revenues (1)16,200 33,915 (17,715)
Cost of sales1,404 4,751 (3,347)
Product margin14,796 29,164 (14,368)
Expenses:
Operating expenses55,907 55,273 634 
General and administrative expenses7,166 8,507 (1,341)
Depreciation and amortization expense18,714 29,184 (10,470)
Loss on disposal or impairment of assets, net71,807 3,350 68,457 
Total expenses153,594 96,314 57,280 
Segment operating (loss) income$(8,441)$70,441 $(78,882)
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Year Ended March 31,
20222021Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3)156,219 427,975 (271,756)
Refined products sold (gallons)776,797 834,717 (57,920)
Refined products sold ($/gallon)$2.446 $1.347 $1.099 
Cost per refined products sold ($/gallon) (4)$2.416 $1.328 $1.088 
Refined products product margin ($/gallon) (4)$0.030 $0.019 $0.011 
Refined products inventory (gallons) (2)1,090 1,223 (133)
Propane sold (gallons)1,034,706 1,364,224 (329,518)
Propane sold ($/gallon)$1.281 $0.753 $0.528 
Cost per propane sold ($/gallon) (4)$1.270 $0.696 $0.574 
Propane product margin ($/gallon) (4)$0.011 $0.057 $(0.046)
Propane inventory (gallons) (2)37,719 51,026 (13,307)
Propane storage capacity leased to third parties (gallons) (2)(3)— 53,947 (53,947)
Butane sold (gallons)588,032 655,256 (67,224)
Butane sold ($/gallon)$1.468 $0.790 $0.678 
Cost per butane sold ($/gallon) (4)$1.351 $0.716 $0.635 
Butane product margin ($/gallon) (4)$0.117 $0.074 $0.043 
Butane inventory (gallons) (2)19,825 20,066 (241)
Butane storage capacity leased to third parties (gallons) (2)(3)— 56,700 (56,700)
Other products sold (gallons)376,906 471,245 (94,339)
Other products sold ($/gallon)$2.099 $0.948 $1.151 
Cost per other products sold ($/gallon) (4)$1.986 $0.900 $1.086 
Other products product margin ($/gallon) (4)$0.113 $0.048 $0.065 
Other products inventory (gallons) (2)18,614 19,195 (581)
(1)    Revenues include $1.3 million and $6.1 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2022 and March 31, 2021, respectively.
(3)    Decrease from March 31, 2021 relates to the sale of Sawtooth on June 18, 2021 (see Note 17 to our consolidated financial statements included in this Annual 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 prices. This was offset by a reduction in volumes sold due to tighter supply in the market. In certain markets in which we compete, allocation of product from suppliers was reduced due to lower demand as a result of the COVID-19 pandemic. We are continuing to work to increase those allocations as demand for refined products increases.

Refined Products Derivative Loss. Our refined products margin during the year ended March 31, 2022 included a realized loss of $2.9 million and the year ended March 31, 2021 included a realized loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions.

Refined Products product margins per gallon of refined products sold for the year ended March 31, 2022 increased from the year ended March 31, 2021 primarily due to supply being short during the three months ended December 31, 2021, as a result of extended refinery downtime in certain markets in which we compete, and being well positioned during the extreme volatility surrounding global events occurring in the three months ended March 31, 2022.

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 domestic 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
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demand due to warmer than normal autumn temperatures, which resulted in lower product demand for crop drying, unusually warm weather during the early winter months and reduced volumes due to the loss of two producer services agreements.

Propane Derivative (Gain) Loss. Our wholesale propane cost of sales included $2.0 millionof net unrealized gains on derivatives and $18.5 million of net realized gains on derivatives during the year ended March 31, 2022. During the year ended March 31, 2021, our cost of wholesale propane sales included $3.3 million of net unrealized gains on derivatives and $14.3 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 winter season, along with increased competition in a number of markets where NGL purchases and sells propane. Midwestern demand was down year-over-year due to lower product demand for crop drying and warmer fall and winter weather. Our margin was also impacted by lower product allocation from certain suppliers and lower storage utilization due to decreased demand and the backwardated market structure.

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 year ended March 31, 2022 included $1.0 millionof net unrealized gains on derivatives and $19.7 million of net realized losses on derivatives. Our cost of butane sales included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives during the year ended March 31, 2021.

Butane product margins per gallon of butane sold were higher during year ended March 31, 2022 than during the year ended March 31, 2021 due primarily to a tight supply market, driven by an increase in demand for exports and an 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 and increased demand for biodiesel. This was partially offset by reduced natural gasoline volumes during the year ended March 31, 2022 as more production was being shipped via pipelines, reducing the availability for product to be shipped by railcars.

Other Products Derivatives Loss (Gain). Our derivatives of other products included $15.8 million of net realized losses on derivatives and there are no unrealized gains or losses on derivatives during the year ended March 31, 2022. Our derivatives of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives.

Other product sales product margins during the year ended March 31, 2022 increased due to an increase in demand for 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 a decline in margin for other natural gas liquids, as favorable supply contracts in the prior year and increased demand in certain markets during the prior year drove favorable sale differentials. Less volatility in the market, for both supply and demand, led to tighter margins for these products during the current period.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the year ended March 31, 2022 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 decrease was primarily due to the disposition of Sawtooth in June 2021 which was partially offset by increased travel as we came out of the pandemic.

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 year ended March 31, 2022, we recorded a net loss of $60.1 million related to the sale of Sawtooth (see Note 17 to our consolidated financial statements included in this Annual Report) 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 year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million due to the write down in value of a terminal we have ceased operating.
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Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Other revenues: 
Revenues$— $1,255 $(1,255)
Cost of sales— 1,816 (1,816)
Loss— (561)561 
Expenses: 
General and administrative expenses41,491 47,520 (6,029)
Depreciation and amortization expense6,959 5,062 1,897 
(Gain) loss on disposal or impairment of assets, net(50)11,001 (11,051)
Total expenses48,400 63,583 (15,183)
Operating loss$(48,400)$(64,144)$15,744 

General and Administrative Expenses. The decrease during the year ended March 31, 2022 was due primarily to lower compensation and legal expenses, offset by increased consulting fees. Compensation expense decreased due to lower equity-based compensation, partially 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.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily due to the write-off of a loan receivable related to the construction of a facility (see Note 17 to our consolidated financial statements included in this Annual Report).

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.4 million during the year ended March 31, 2022, compared to $1.9 million during the year ended March 31, 2021. The decrease of $0.5 million during the year ended March 31, 2022 was due primarily to lower earnings from certain membership interests related to specific land and water services operations.

Interest Expense

The following table summarizes the components of our consolidated interest expense for the periods indicated:
Year Ended March 31,
20222021Change
(in thousands)
Senior secured notes$153,750 $24,344 $129,406 
Senior unsecured notes87,766 96,711 (8,945)
Amortization of debt issuance costs16,960 13,420 3,540 
Revolving credit facility10,077 46,500 (36,423)
Other3,087 17,824 (14,737)
Total$271,640 $198,799 $72,841 

The increase of $72.8 million during the year ended March 31, 2022 was primarily due to the issuance of the 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) which resulted in us paying a higher interest rate on certain refinanced indebtedness. This increase was partially offset by the termination of the term credit agreement as well as the repurchases of a portion of our senior unsecured notes to mature in 2023 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report).

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Gain (Loss) on Early Extinguishment of Liabilities, Net

Gain on early extinguishment of liabilities, net was $1.8 million during the year ended March 31, 2022, compared to a loss on early extinguishment of liabilities, net of $16.7 million during the year ended March 31, 2021. During the years ended March 31, 2022 and 2021, the net gain (loss) (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 7 to our consolidated financial statements included in this Annual Report for a further discussion.

Other Income (Expense), Net

Other income, net was $2.3 million during the year ended March 31, 2022, compared to other expense, net of $36.5 million during the year ended March 31, 2021. The decrease in other expense, net of $38.8 million during the year ended March 31, 2022 was due primarily to a $40.0 million fee paid to the holders of the 9.00% Class D Preferred Units (“Class D Preferred Units”) during the year ended March 31, 2021 to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the $500.0 million asset-based revolving credit facility (“ABL Facility”) (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.

Income Tax (Expense) Benefit

Income tax expense was $1.0 million during the year ended March 31, 2022, compared to an income tax benefit of $3.4 million during the year ended March 31, 2021. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Noncontrolling interest income was $0.7 million during the year ended March 31, 2022, compared to $0.6 million during the year ended March 31, 2021. The increase of less than $0.1 million during the year ended March 31, 2022 was due primarily to higher income from certain recycling operations, partially offset by a higher loss from operations of the Sawtooth joint venture primarily due to the sale of Sawtooth in June 2021 and lower income from certain water solutions operations.


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Segment Operating Results for the Years Ended March 31, 2021 and 2020

Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated. As previously reported, on July 2, 2019, we acquired all of the assets of Mesquite and on October 31, 2019, we acquired all of the equity interests of Hillstone, thus the fiscal year 2020 results only include a partial year of operations related to these transactions.
 Year Ended March 31,
 20212020Change
 (in thousands, except per barrel and per day amounts)
Revenues:   
Water disposal service fees$308,511 $305,124 $3,387 
Sale of recovered crude oil28,599 59,445 (30,846)
Recycled water3,015 705 2,310 
Other revenues30,861 56,785 (25,924)
Total revenues370,986 422,059 (51,073)
Expenses:   
Cost of sales-excluding impact of derivatives2,557 5,511 (2,954)
Derivative loss (gain)7,065 (39,381)46,446 
Operating expenses142,371 192,987 (50,616)
General and administrative expenses6,403 7,939 (1,536)
Depreciation and amortization expense222,107 163,588 58,519 
Loss on disposal or impairment of assets, net76,942 255,285 (178,343)
Revaluation of liabilities6,261 9,194 (2,933)
Total expenses463,706 595,123 (131,417)
Segment operating loss$(92,720)$(173,064)$80,344 
Produced water processed (barrels per day)
Delaware Basin (1)1,148,582 1,170,158 (21,576)
Eagle Ford Basin78,397 246,784 (168,387)
DJ Basin111,016 164,936 (53,920)
Other Basins26,596 61,091 (34,495)
Total1,364,591 1,642,969 (278,378)
Recycled water (barrels per day)43,503 14,992 28,511 
Total (barrels per day)1,408,094 1,657,961 (249,867)
Skim oil sold (barrels per day)1,957 3,397 (1,440)
Service fees for produced water processed ($/barrel) (2)$0.62 $0.63 $(0.01)
Recovered crude oil for produced water processed ($/barrel) (2)$0.06 $0.12 $(0.06)
Operating expenses for produced water processed ($/barrel) (2)$0.29 $0.40 $(0.11)
(1)    During the year ended March 31, 2020, barrels per day of producedwater processed by the assets acquired in the Mesquite and Hillstone transactions are calculated by the number of days in which we owned the assets.
(2)    Total producedwater barrels processed during the years ended March 31, 2021 and 2020 were 498,075,843 and 485,115,941, respectively.

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in the volume of produced water processed primarily driven by our acquisitions of Mesquite and Hillstone as well as new produced water volumes received upon the completion and commencement of the Partnership’s Poker Lake pipeline. The pipeline was successfully completed in October 2020 with a capacity of over 400,000 barrels per day and connects into our integrated Delaware Basin produced water pipeline infrastructure network. These increases were partially offset by a decrease in the volume of other produced water processed resulting from lower crude oil prices, development activity and production volumes.

Recovered Crude Oil Revenues. The decrease was due primarily to a reduction in the number of producing wells completed in our area of operations, a decrease in the percentage of skim oil volumes recovered per produced water barrel processed and lower crude oil prices. The lower percentage of skim oil volumes recovered was due primarily to an increase in
65



produced water transported through pipelines (which contains less oil per barrel of produced water), and the addition of contract structures that allow producers to keep the skim oil recovered from produced water.

Recycled Water Revenues. The increase was due primarily to the timing of our customers completions driven by an increase in drilling and completion activity primarily in the Delaware Basin.

Other Revenues. The decrease was due primarily to reduced customer development activity and needs for these services resulting from the decline in crude oil prices.

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to lower purchasing and transportation costs related to our brackish non-potable water and crude oil sales.

Derivative Loss (Gain). During the year ended March 31, 2021, we had $24.5 million of net unrealized losses on derivatives and $17.4 million of net realized gains on derivatives. During the year ended March 31, 2020, we had $29.9 million of net unrealized gains on derivatives and $9.5 million of net realized gains on derivatives. In June 2019, we settled derivative contracts that had scheduled settlement dates from April through December 2020 and recorded a gain of $1.9 million on those derivatives.

Operating and General and Administrative Expenses. The decrease was due primarily to the deployment of automation and subsequent reduction in employee headcount, reduced equipment rental (including generators) and associated diesel fuel and repairs and lower maintenance expense. In addition, acquisition expenses were lower by $4.1 million as we did not close on any acquisitions during the year ended March 31, 2021.

Depreciation and Amortization Expense.The increase was due primarily to Mesquite and Hillstone acquisitions completed in the prior year and newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded:

an impairment charge of $72.4 million to write down the value of an asset group and certain intangible assets due to a decline in producer activity, resulting in lower disposal volumes (see Note 4 and Note 6 to our consolidated financial statements included in this Annual Report);
an impairment charge of $11.9 million to write down the value of certain inactive or underutilized saltwater disposal facilities (see Note 4 to our consolidated financial statements included in this Annual Report);
a net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets (see Note 4 to our consolidated financial statements included in this Annual Report); and
a gain of $14.0 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17 to our consolidated financial statements included in this Annual Report).

During the year ended March 31, 2020, we recorded:

a goodwill impairment charge of $250.0 million related to the current macroeconomic conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, resulting in expected decreases in future cash flows for certain of our assets (see Note 5 to our consolidated financial statements included in this Annual Report);
an impairment charge of $13.5 million related to certain inactive saltwater disposal facilities;
a net loss of $9.2 million on the disposals of certain other assets;
a gain of $14.5 million for the sale of certain water permits (see Note 17 to our consolidated financial statements included in this Annual Report); and
a gain of $1.0 million for cash received related to a loan receivable that was previously written off.

Revaluation of Liabilities. During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.
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During the year ended March 31, 2020, a portion of the revaluation of liabilities represented the change in the valuation of our contingent consideration liability issued by us as part of a business combination. Under the agreement, we were required to make additional payments to the seller based on the volume of produced water processed by the assets acquired. During the year ended March 31, 2020, the thresholds for the volume of produced water processed were surpassed, thus triggering our obligation to pay the seller.

During the year ended March 31, 2020, there was a reduction in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers and an increase in facilities due to acquisitions, resulting in a decrease to the expected future royalty payment.

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per barrel amounts)
Revenues:
Crude oil sales$1,574,699 $2,383,812 $(809,113)
Crude oil transportation and other153,588 184,129 (30,541)
Total revenues (1)1,728,287 2,567,941 (839,654)
Expenses:   
Cost of sales-excluding impact of derivatives1,473,330 2,347,863 (874,533)
Derivative loss (gain)49,314 (35,736)85,050 
Operating expenses56,918 61,708 (4,790)
General and administrative expenses8,038 6,723 1,315 
Depreciation and amortization expense60,874 70,759 (9,885)
Loss (gain) on disposal or impairment of assets, net384,143 (1,144)385,287 
Total expenses2,032,617 2,450,173 (417,556)
Segment operating (loss) income$(304,330)$117,768 $(422,098)
Crude oil sold (barrels)38,349 42,799 (4,450)
Crude oil transported on owned pipelines (barrels)32,797 45,884 (13,087)
Crude oil storage capacity - owned and leased (barrels) (2)5,239 5,362 (123)
Crude oil storage capacity leased to third parties (barrels) (2)1,501 2,062 (561)
Crude oil inventory (barrels) (2)1,201 1,111 90 
Crude oil sold ($/barrel)$41.062 $55.698 $(14.636)
Cost per crude oil sold ($/barrel) (3)$38.419 $54.858 $(16.439)
Crude oil product margin ($/barrel) (3)$2.643 $0.840 $1.803 
(1)    Revenues include $6.7 million and $18.2 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(3)    Cost and product margin per barrel excludes the impact of derivatives.

Crude Oil Sales Revenues. The decrease was due primarily to a decrease in crude oil prices and sales volumes during the year ended March 31, 2021, compared to the year ended March 31, 2020. The volumes decreased due to changes in the method of delivery to the market in the Permian region, as a significant amount of production switched to long haul pipeline owned and controlled by others.

Crude Oil Transportation and Other Revenues. The decrease was primarily due to our Grand Mesa Pipeline, which decreased revenues by $32.8 million during the year ended March 31, 2021, compared to the year ended March 31, 2020. During the year ended March 31, 2021, financial volumes on the Grand Mesa Pipeline averaged approximately $134.794,000 barrels per day, compared to 131,000 barrels per day for the year ended March 31, 2020 (volume amounts are from both internal and
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external parties) primarily due to the court approved rejection of the Extraction transportation agreement (see Note 17 to our consolidated financial statements included in this Annual Report).

Cost of Sales-Excluding Impact of Derivatives. The decrease was due to a decrease in crude oil prices and reduced volumes during the year ended March 31, 2021, compared to the year ended March 31, 2020.

Derivative Loss (Gain). Our cost of sales during the year ended March 31, 2021 included $25.9 million remainedof net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives. The losses are due to a very volatile pricing market during the year ended March 31, 2021. Our cost of sales during the year ended March 31, 2020 included $24.4 million of net realized gains on derivatives and $11.3 million of net unrealized gains on derivatives. In March 2020, we closed realized derivative contracts that had scheduled settlement dates from May 2020 through June 2020, which accounted for $16.7 million of the realized gains for the prior year.

Crude Oil Product Margin. The increase was due to inventory purchased during the three months ended June 30, 2020 at lower prices and held for sale during the three months ended September 30, 2020 and the three months ended December 31, 2020 when prices recovered.

Operating and General and Administrative Expenses.Expenses decreased compared to the prior year due to a decrease of utilities, as lower volumes were being shipped on the Grand Mesa Pipeline and other cost cutting measures which were partially offset by the write off of a $5.7 million receivable from Extraction (see Note 17 to our consolidated financial statements included in this Annual Report).

Depreciation and Amortization Expense. The decrease was due to the retirement of certain assets and other assets being fully depreciated or amortized during the year ended March 31, 2020.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report), and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report). During the year ended March 31, 2020, we recorded a net gain of $1.1 million related to the disposal of certain assets.



















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Liquids Logistics

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Refined products sales:
Revenues-excluding impact of derivatives (1)(2)$1,124,087 $2,394,663 $(1,270,576)
Cost of sales-excluding impact of derivatives (3)1,108,493 2,367,850 (1,259,357)
Derivative loss (gain)930 (3,225)4,155 
Product margin14,664 30,038 (15,374)
Propane sales:
Revenues (1)1,027,582 846,756 180,826 
Cost of sales-excluding impact of derivatives949,402 766,521 182,881 
Derivative loss10,994 3,536 7,458 
Product margin67,186 76,699 (9,513)
Butane sales:
Revenues (1)517,857 564,016 (46,159)
Cost of sales-excluding impact of derivatives469,394 486,777 (17,383)
Derivative loss (gain)22,353 (8,288)30,641 
Product margin26,110 85,527 (59,417)
Other product sales:
Revenues-excluding impact of derivatives (1)446,744 775,458 (328,714)
Cost of sales-excluding impact of derivatives424,191 732,967 (308,776)
Derivative gain(7,078)(2,846)(4,232)
Product margin29,631 45,337 (15,706)
Service revenues:
Revenues (1)33,915 40,216 (6,301)
Cost of sales4,751 9,207 (4,456)
Product margin29,164 31,009 (1,845)
Expenses:
Operating expenses55,273 77,980 (22,707)
General and administrative expenses8,507 12,644 (4,137)
Depreciation and amortization expense29,184 27,930 1,254 
Loss on disposal or impairment of assets, net3,350 7,645 (4,295)
Total expenses96,314 126,199 (29,885)
Segment operating income$70,441 $142,411 $(71,970)
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Year Ended March 31,
20212020Change
(in thousands, except per gallon amounts)
Natural gas liquids and refined products storage capacity - owned and leased (gallons) (4)427,975 400,301 27,674 
Refined products sold (gallons)834,717 1,272,546 (437,829)
Refined products sold ($/gallon)$1.347 $1.890 $(0.543)
Cost per refined products sold ($/gallon) (5)$1.328 $1.861 $(0.533)
Refined products product margin ($/gallon) (5)$0.019 $0.029 $(0.010)
Refined products inventory (gallons) (4)1,223 2,391 (1,168)
Propane sold (gallons)1,364,224 1,478,759 (114,535)
Propane sold ($/gallon)$0.753 $0.573 $0.180 
Cost per propane sold ($/gallon) (5)$0.696 $0.518 $0.178 
Propane product margin ($/gallon) (5)$0.057 $0.055 $0.002 
Propane inventory (gallons) (4)51,026 57,221 (6,195)
Propane storage capacity leased to third parties (gallons) (4)53,947 46,066 7,881 
Butane sold (gallons)655,256 814,528 (159,272)
Butane sold ($/gallon)$0.790 $0.692 $0.098 
Cost per butane sold ($/gallon) (5)$0.716 $0.598 $0.118 
Butane product margin ($/gallon) (5)$0.074 $0.094 $(0.020)
Butane inventory (gallons) (4)20,066 24,808 (4,742)
Butane storage capacity leased to third parties (gallons) (4)56,700 33,894 22,806 
Other products sold (gallons)471,245 602,872 (131,627)
Other products sold ($/gallon)$0.948 $1.286 $(0.338)
Cost per other products sold ($/gallon) (5)$0.900 $1.216 $(0.316)
Other products product margin ($/gallon) (5)$0.048 $0.070 $(0.022)
Other products inventory (gallons) (4)19,195 26,126 (6,931)
(1)    Revenues include $6.1 million and $5.0 million of intersegment sales during the years ended March 31, 2021 and 2020, respectively, that are eliminated in our consolidated statements of operations.
(2)    Revenues include $10.3 million of intersegment sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(3)    Cost of sales include $8.2 million of intersegment cost of sales during the year ended March 31, 2020 between certain businesses within the Liquids Logistics segment and TPSL, Mid-Con and Gas Blending that are eliminated in our consolidated statement of operations.
(4)    Information is presented as of March 31, 2021 and March 31, 2020, respectively.
(5)    Cost and product margin per gallon excludes the impact of derivatives.

Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales, excluding the impact of derivatives, were due to a decrease in refined products prices and volumes due to the sizable reduction in demand for both gasoline and diesel products due to the COVID-19 pandemic. There was also a large decrease in volumes due to the elimination of our sales in the Northeast and Southeast due to our non-compete clause with the purchaser of our TPSL business.

Refined Products Derivative Loss (Gain). Our margin during the year ended March 31, 2021 included a loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions. Our margin during the year ended March 31, 2020 included a gain of $3.2 million from our risk management activities due primarily to unrealized gains on our open forward physical positions and decreases in NYMEX futures prices on our short future positions.

Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales-excluding impact of derivatives were due to increased commodity prices in the fourth quarter of the year ended March 31, 2021, as a result of winter storm Uri in February 2021. These increases were partially offset by lower volumes as a result of lower commercial and industrial demand due to the COVID-19 pandemic.
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Propane Derivative Loss. Our cost of wholesale propane sales included $3.3 million of net unrealized gains on derivatives and $14.3 million of net realized losses on derivatives during the year ended March 31, 2021. During the year ended March 31, 2020, our cost of wholesale propane sales included $1.5 million of net unrealized losses on derivatives and $2.0 million of net realized losses on derivatives.

Propane product margins per gallon of propane sold were higher during the year ended March 31, 2021 than during the year ended March 31, 2020 due primarily to inventory values aligning with reduced commodity prices at index markets as well as the extreme cold weather in February 2021.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales-excluding impact of derivatives in butane were due primarily to lower product demand which decreased due to lower gasoline blending volumes and decreased export sales related to the COVID-19 pandemic.

Butane Derivative Loss (Gain). Our cost of butane sales during the year ended March 31, 2021 included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives. Our cost of butane sales included $0.5 million of net unrealized losses on derivatives and $8.8 million of net realized gains on derivatives during the year ended March 31, 2020.

Butane product margins per gallon of butane sold were lower during the year ended March 31, 2021 than during the year ended March 31, 2020 due primarily to the weaker domestic market demand due to COVID-19.

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in revenues and cost of sales - excluding the impact of derivatives, were due to lower commodity prices and lower demand due to the lockdowns related to the COVID-19 pandemic.

Other Products Derivative Gain. Our cost of sales of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives. Our cost of sales of other products included $0.6 million of net unrealized losses on derivatives and $3.4 million of net realized gains on derivatives during the year ended March 31, 2020.

Other product sales product margins during the year ended March 31, 2021 decreased primarily due to softer product demand during the COVID-19 pandemic and associated economic slowdown. In addition, the margin for the year ended March 31, 2020, included a biodiesel tax credit of $13.8 million. The impact of the biodiesel tax credit for the year March 31, 2021 was approximately $0.4 million.

Service Revenues. This revenue includes storage, terminaling and transportation services income. The decrease during the year ended March 31, 2021 was primarily to weaker demand as producers shut-in and curtailed production.

Operating and General and Administrative Expenses. Expenses decreased for the year ended March 31, 2021 due to lower volumes and services rendered as well as reduced costs with lower incentive compensation and restricted travel due to COVID-19.

Depreciation and Amortization Expense. Expense for the year ended March 31, 2021 was higher due to the acceleration of depreciation expense prior to the sale of a terminal facility.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million to the write down in value of a terminal we have ceased operating. During the year ended March 31, 2020, we recorded an impairment of $7.7 million due to adjusting the cost basis of pipeline linefill to the market price of propane as of March 31, 2020.

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Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Other revenues: 
Revenues$1,255 $1,038 $217 
Cost of sales1,816 1,774 42 
Loss(561)(736)175 
Expenses: 
Operating expenses— 318 (318)
General and administrative expenses47,520 86,358 (38,838)
Depreciation and amortization expense5,062 3,035 2,027 
Loss on disposal or impairment of assets, net11,001 — 11,001 
Total expenses63,583 89,711 (26,128)
Operating loss$(64,144)$(90,447)$26,303 

General and Administrative Expenses. The decrease during the year ended March 31, 2021 was due primarily to lower equity-based compensation expense and acquisition expenses. During the year ended March 31, 2021, equity-based compensation expense was $6.7 million, compared to $26.5 million during the year ended March 31, 2020. During the year ended March 31, 2021, acquisition expenses were $1.7 million, compared to $15.6 million during the year ended March 31, 2020. The driver behind the decrease in acquisition expenses was primarily due to expenses incurred in connection with our acquisitions of both Mesquite and Hillstone in the year ended March 31, 2020.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2021, we recorded a net loss of $11.0 million, which was primarily 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 (see Note 17 to our consolidated financial statements included in this Annual Report ) and a loss from the write-off of installment payments made in connection with an option agreement to invest in a third party.

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $1.9 million during the year ended March 31, 2021, compared to $1.3 million during the year ended March 31, 2020. The increase of $0.6 million during the year ended March 31, 2021 was due primarily to higher earnings from certain membership interests acquired in November 2019 related to specific land and water services operations, partially offset by a higher loss from our interest in an aircraft company during the year ended March 31, 2021.

Interest Expense

The following table summarizes the components of our consolidated interest expense for the periods indicated:
Year Ended March 31,
20212020Change
(in thousands)
Senior unsecured notes$96,711 $102,289 $(5,578)
Revolving credit facility46,500 57,470 (10,970)
Senior secured notes24,344 — 24,344 
Amortization of debt issuance costs13,420 10,901 2,519 
Other17,824 10,524 7,300 
Total$198,799 $181,184 $17,615 

The increase of $17.6 million during the year ended March 31, 2021 was due to the issuance of the 2026 Senior Secured Notes. This increase was offset by repurchases of a portion of our senior unsecured notes to mature in 2023, 2025 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report).
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(Loss) Gain on Early Extinguishment of Liabilities, Net

Loss on early extinguishment of liabilities, net was $16.7 million during the year ended March 31, 2021, compared to a gain on early extinguishment of liabilities, net of $1.3 million during the year ended March 31, 2020. During the years ended March 31, 2021 and 2020, the net (loss) gain (inclusive of debt issuance costs written off) relates to the early extinguishment of a portion of the outstanding senior unsecured notes. See Note 7 to our consolidated financial statements included in this Annual Report for a further discussion.

Other (Expense) Income, Net

Other expense, net was $36.5 million during the year ended March 31, 2021, compared to other income, net of $1.7 million during the year ended March 31, 2020. The increase in other expense, net of $38.2 million during the year ended March 31, 2021 was due primarily to a $40.0 million fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.

Income Tax Benefit (Expense)

Income tax benefit was $3.4 million during the year ended March 31, 2021, compared to income tax expense of $0.3 million during the year ended March 31, 2020. The increase in the income tax benefit during the year ended March 31, 2021 was primarily due to a full year of Hillstone operations during the year ended March 31, 2021 compared to five months of Hillstone operations during the year ended March 31, 2020. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.

Noncontrolling Interests

Noncontrolling interest income was $0.6 million during the year ended March 31, 2021, compared to a noncontrolling interest loss of $1.8 million during the year ended March 31, 2020. The increase in noncontrolling interest income of $2.4 million during the year ended March 31, 2021 was due primarily to a lower loss from operations from certain water operations, income from operations from the Sawtooth joint venture and higher income from operations of certain assets we acquired in Mesquite acquisition in July 2019.

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 the TPSL, Mid-Con, and Gas Blending businesses, 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 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.

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Other than for the TPSL, Mid-Con, and Gas Blending businesses, which are included in discontinued operations, and 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 the TPSL, Mid-Con, and Gas Blending businesses, which are included in discontinued operations, and 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.

The following table reconciles net loss to EBITDA and Adjusted EBITDA for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Net loss$(184,101)$(639,187)$(398,780)
Less: Net (income) loss attributable to noncontrolling interests(655)(632)1,773 
Net loss attributable to NGL Energy Partners LP(184,756)(639,819)(397,007)
Interest expense271,689 198,823 181,357 
Income tax expense (benefit)971 (3,444)365 
Depreciation and amortization287,943 314,476 265,147 
EBITDA375,847 (129,964)49,862 
Net unrealized (gains) losses on derivatives(14,977)47,366 (38,557)
CMA Differential Roll net losses (gains) (1)67,738 — — 
Inventory valuation adjustment (2)8,409 1,224 (29,676)
Lower of cost or net realizable value adjustments10,862 (30,102)31,202 
Loss on disposal or impairment of assets, net94,059 476,601 464,483 
(Gain) loss on early extinguishment of liabilities, net(1,851)16,692 (1,341)
Equity-based compensation expense (3)(1,052)6,727 26,510 
Acquisition expense (4)67 1,711 19,722 
Revaluation of liabilities (5)(6,495)6,261 9,194 
Class D Preferred Unitholder consent fee (6)— 40,000 — 
Other (7)9,909 11,135 15,788 
Adjusted EBITDA$542,516 $447,651 $547,187 
Adjusted EBITDA - Discontinued Operations (8)$— $(621)$(42,270)
Adjusted EBITDA - Continuing Operations$542,516 $448,272 $589,457 
(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.
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(3)    Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 9 to our consolidated financial statements included in this Annual 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 9 to our 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, including Mesquite and Hillstone.
(5)    Amounts for the years ended March 31, 2022 and 2021 represent the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment. Amount for the year ended March 31, 2020 represents the non-cash valuation adjustment of our contingent consideration liability issued by us as part of our acquisition of Mesquite, partially offset by the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.
(6)    Represents the fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report).
(7)    Amounts for the years ended March 31, 2022, 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.
(8)    Amounts include the operations of TPSL, Gas Blending and Mid-Con.

The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Reconciliation to consolidated statements of operations:
Depreciation and amortization per EBITDA table$287,943 $314,476 $265,147 
Intangible asset amortization recorded to cost of sales(281)(307)(349)
Depreciation and amortization of unconsolidated entities(768)(756)(561)
Depreciation and amortization attributable to noncontrolling interests1,826 3,814 3,535 
Depreciation and amortization attributable to discontinued operations— — (2,460)
Depreciation and amortization per consolidated statements of operations$288,720 $317,227 $265,312 
Reconciliation to consolidated statements of cash flows:
Depreciation and amortization per EBITDA table$287,943 $314,476 $265,147 
Amortization of debt issuance costs recorded to interest expense16,960 13,419 10,901 
Amortization of royalty expense recorded to operating expense247 247 286 
Depreciation and amortization of unconsolidated entities(768)(756)(561)
Depreciation and amortization attributable to noncontrolling interests1,826 3,814 3,535 
Depreciation and amortization attributable to discontinued operations— — (2,460)
Depreciation and amortization per consolidated statements of cash flows$306,208 $331,200 $276,848 
The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements of operations for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Interest expense per EBITDA table$271,689 $198,823 $181,357 
Interest expense attributable to noncontrolling interests16 47 — 
Interest expense attributable to unconsolidated entities(65)(71)(62)
Interest expense attributable to discontinued operations— — (111)
Interest expense per consolidated statements of operations$271,640 $198,799 $181,184 

75


The following table summarizes additional amounts attributable to discontinued operations in the EBITDA table above for the periods indicated:
Year Ended March 31,
20212020
(in thousands)
Income tax (benefit) expense$(53)$20 
Inventory valuation adjustment$27 $(27,526)
Lower of cost or net realizable value adjustments$(27)$(991)
Loss on disposal or impairment of assets, net$1,174 $203,990 

The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated.
Year Ended March 31, 2022
Water
Solutions
Crude Oil
Logistics
Liquids LogisticsCorporate
and
Other
Consolidated
(in thousands)
Operating income (loss)$94,851 $45,033 $(8,441)$(48,400)$83,043 
Depreciation and amortization214,558 48,489 18,714 6,959 288,720 
Amortization recorded to cost of sales— — 281 — 281 
Net unrealized losses (gains) on derivatives11,652 (23,664)(2,965)— (14,977)
CMA Differential Roll net losses (gains)— 67,738 — — 67,738 
Inventory valuation adjustment— — 8,409 — 8,409 
Lower of cost or net realizable value adjustments— 2,235 8,627 — 10,862 
Loss (gain) on disposal or impairment of assets, net25,598 (3,101)71,807 (50)94,254 
Equity-based compensation expense— — — (1,052)(1,052)
Acquisition expense— — 63 67 
Other income, net718 353 711 472 2,254 
Adjusted EBITDA attributable to unconsolidated entities2,363 — 14 (145)2,232 
Adjusted EBITDA attributable to noncontrolling interest(2,212)— (528)— (2,740)
Revaluation of liabilities(6,495)— — — (6,495)
Other921 9,064 (65)— 9,920 
Adjusted EBITDA$341,958 $146,147 $96,564 $(42,153)$542,516 
76


Year Ended March 31, 2021
Water
Solutions
Crude Oil
Logistics
Liquids LogisticsCorporate
and
Other
Continuing OperationsDiscontinued Operations (TPSL, Mid-Con, Gas Blending)Consolidated
(in thousands)
Operating (loss) income$(92,720)$(304,330)$70,441 $(64,144)$(390,753)$— $(390,753)
Depreciation and amortization222,107 60,874 29,184 5,062 317,227 — 317,227 
Amortization recorded to cost of sales— — 307 — 307 — 307 
Net unrealized losses (gains) on derivatives24,500 23,432 (566)— 47,366 — 47,366 
Inventory valuation adjustment— — 1,197 — 1,197 — 1,197 
Lower of cost or net realizable value adjustments— (29,458)(617)— (30,075)— (30,075)
Loss on disposal or impairment of assets, net76,942 384,143 3,350 11,001 475,436 — 475,436 
Equity-based compensation expense— — — 6,727 6,727 — 6,727 
Acquisition expense27 — — 1,684 1,711 — 1,711 
Other income (expense), net266 1,565 1,301 (39,635)(36,503)— (36,503)
Adjusted EBITDA attributable to unconsolidated entities3,019 — (3)(252)2,764 — 2,764 
Adjusted EBITDA attributable to noncontrolling interest(1,647)— (2,887)— (4,534)— (4,534)
Revaluation of liabilities6,261 — — — 6,261 — 6,261 
Class D Preferred Unitholder consent fee— — — 40,000 40,000 — 40,000 
Intersegment transactions (1)— — (27)— (27)— (27)
Other2,751 8,317 100 — 11,168 — 11,168 
Discontinued operations— — — — — (621)(621)
Adjusted EBITDA$241,506 $144,543 $101,780 $(39,557)$448,272 $(621)$447,651 
77


Year Ended March 31, 2020
Water
Solutions
Crude Oil
Logistics
Liquids LogisticsCorporate
and
Other
Continuing OperationsDiscontinued Operations (TPSL, Mid-Con, Gas Blending)Consolidated
(in thousands)
Operating (loss) income$(173,064)$117,768 $142,411 $(90,447)$(3,332)$— $(3,332)
Depreciation and amortization163,588 70,759 27,930 3,035 265,312 — 265,312 
Amortization recorded to cost of sales— — 349 — 349 — 349 
Net unrealized (gains) losses on derivatives(29,861)(11,315)2,619 — (38,557)— (38,557)
Inventory valuation adjustment— — (2,150)— (2,150)— (2,150)
Lower of cost or net realizable value adjustments— 29,469 2,724 — 32,193 — 32,193 
Loss (gain) on disposal or impairment of assets, net255,285 (1,144)7,645 — 261,786 — 261,786 
Equity-based compensation expense— — — 26,510 26,510 — 26,510 
Acquisition expense4,079 — — 15,643 19,722 — 19,722 
Other (expense) income, net(448)717 21 1,394 1,684 — 1,684 
Adjusted EBITDA attributable to unconsolidated entities2,152 — 24 (263)1,913 — 1,913 
Adjusted EBITDA attributable to noncontrolling interest(1,210)— (1,842)— (3,052)— (3,052)
Revaluation of liabilities9,194 — — — 9,194 — 9,194 
Intersegment transactions (1)— — 2,099 — 2,099 — 2,099 
Other2,607 12,965 214 — 15,786 — 15,786 
Discontinued operations— — — — — (42,270)(42,270)
Adjusted EBITDA$232,322 $219,219 $182,044 $(44,128)$589,457 $(42,270)$547,187 
(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 purchases of inventory, capital expenditures, interest and repayment of debt maturities.

On February 4, 2021, we closed on our $2.05 billion 2026 Senior Secured Notes offering and entered into a $500.0 million ABL Facility. See Note 7 to our consolidated financial statements included in this Annual Report for a further discussion of these transactions and a description of the 2026 Senior Secured Notes and ABL Facility. These transactions extended the maturity of our debt and provided us with improved liquidity. In conjunction with the transaction, we agreed to certain restricted payment provisions, one of which requires us to temporarily suspend the quarterly common unit distribution which began with the quarter ended December 31, 2020, as well as distributions on all of our preferred units, which began with the quarter ended March 31, 2021, until our total leverage ratio (as defined in the indenture for the 2026 Senior Secured Notes) falls below 4.75 to 1.00. The cash savings from the suspension of the distributions should accelerate the deleveraging of our balance sheet and increase our liquidity and should create more financial flexibility going forward.

We believe that our anticipated cash flows from operations and the borrowing capacity under the 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.

78


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 saleuse 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

On February 4, 2021, we closed on the $500.0 million ABL Facility, which provides liquidity to operate our business and manage our working capital requirements. The ABL Facility is scheduled to mature at the earliest of (a) February 4, 2026 or (b) 91 days prior to the earliest 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. 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 ATM Program atABL Facility. At March 31, 2019.2022, $116.0 million had been borrowed under the ABL Facility and we had letters of credit outstanding of approximately $155.1 million.


On April 13, 2022, we amended the ABL Facility to increase the commitments to $600.0 million under the accordion feature within the ABL Facility. As part of the amendment, we agreed to reduce the commitments back to $500.0 million on or before March 31, 2023. In addition, the sub-limit for letters of credit was increased to $250.0 million. The increase in the commitments was to support working capital needs through the existing higher commodity price environment.

As of March 31, 2022, our current assets exceeded our current liabilities by approximately $269.1 million.

For additional information related to our ABL Facility, see Note 7 to our consolidated financial statements included in this Annual Report.

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 2026 Senior Secured Notes in a private placement. The 2026 Senior Secured Notes bear interest at 7.50%, which is payable on February 1 and August 1 of each year, beginning 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 (“2026 Notes”) (collectively, the “Senior Unsecured Notes”).

Repurchases

During the year ended March 31, 2022, we repurchased $79.5 million of the 2023 Notes and $6.0 million of the 2026 Notes at a cumulative cash cost of $83.2 million (excluding payments of accrued interest).

79


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 (seeNote 17 to our consolidated financial statements included in this Annual 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 $23.9 million when this loan matures on November 1, 2027.

For additional information related to our long-term debt, see Note 7 to our consolidated financial statements included in this Annual Report.

Capital Expenditures, Acquisitions and Other Investments

The following table summarizes expansion and maintenance capital expenditures (which excludes additions for tank bottoms and line filllinefill and has been prepared on the accrual basis), acquisitions and other investments for the periods indicated.
Capital ExpendituresOther
Year Ended March 31,Expansion (1)MaintenanceAcquisitionsInvestments (2)
(in thousands)
2022$75,554 $59,468 $— $350 
2021$90,920 $28,787 $(901)$963 
2020$571,154 $61,353 $1,268,474 $21,218 
(1)    Amounts for the years ended March 31, 2021 and 2020 include $18.2 million and $49.1 million, respectively, of transactions classified as acquisitions of assets.
(2)    Amounts for the years ended March 31, 2022, 2021 and 2020 primarily related to contributions made to unconsolidated entities and the purchase of membership interests in a water services and land company in November 2019.

Capital expenditures for the year ending March 31, 2023 are expected to be approximately $100 million.

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 table below includesuspension of the quarterly common unit distributions, which began with the quarter ended December 31, 2020, and all preferred unit distributions, which began 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 acquisitions relatedthe overall performance of our businesses.

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

Contractual Obligations

Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, pipeline commitments, asset retirement obligations and other commitments.

Purchase Commitments

Our fixed-price and index-price commodity purchase commitments result from contracts we have entered into for which we expect the parties to physically settle and deliver the inventory in future periods. As of March 31, 2022, our former Retail Propane segment.
  Capital Expenditures   Other
Year Ended March 31, Expansion (1) Maintenance (2) Acquisitions (3) Investments (4)
  (in thousands)
2019 $418,920
 $49,177
 $348,836
 $389
2018 $155,213
 $37,713
 $50,417
 $27,889
2017 $334,383
 $26,073
 $122,832
 $44,864
(1)Amount for the year ended March 31, 2018 includes intangible assets received as consideration as part of the Sawtooth joint venture transaction (see Note 16 to our consolidated financial statements included in this Annual Report). Amounts for the years ended March 31, 2019, 2018 and 2017 include $0.4 million, $8.5 million and $5.4 million, respectively, related to our former Retail Propane segment.
(2)Amounts for the years ended March 31, 2019, 2018 and 2017 include $3.8 million, $14.0 million and $13.6 million, respectively, related to our former Retail Propane segment.
(3)Amounts for the years ended March 31, 2019, 2018 and 2017 include $31.9 million, $30.5 million and $80.9 million, respectively, related to our former Retail Propane segment.
(4)Amounts for the years ended March 31, 2019 and 2018 primarily related to contributions made to unconsolidated entities. Amount for the year ended March 31, 2017 primarily related to payments made to terminate a development agreement and other liabilities. There were no amounts related to our former Retail Propane segment for the years ended March 31, 2019, 2018 or 2017.

We currently expect to invest approximately $1.2purchase commitments totaled $10.1 billion, to $1.3with $5.5 billion on acquisitions and growth capital expenditures during fiscal year 2020, which includes approximately $970 million for the acquisition of Mesquite Disposals Unlimited, LLC and certain other transactions in our Water Solutions segment that have already closed (see due within one year. See Note 198 to our consolidated financial statements included in this Annual Report).Report for information regarding our commodity purchase commitments and timing of our expected purchase commitments payments.

80


Debt Principal and Interest Obligations

As of March 31, 2022, our aggregate principal amount of outstanding debt was $3.4 billion, with $2.4 million due within one year. Our obligation for interest on the debt totaled $903.3 million, with $246.3 million due within one year, based on our outstanding balances and interest rates as of March 31, 2022. See Note 7 to our consolidated financial statements included in this Annual Report for information regarding our outstanding debt principal and interest obligations and timing of our expected payments.

Operating Lease Obligations

As of March 31, 2022, our undiscounted operating lease obligation was $145.9 million, with $46.6 million due within one year. See Note 15 to our consolidated financial statements included in this Annual Report for information regarding our lease obligations and timing of our expected lease payments.

Pipeline Commitments

Our pipeline commitments are noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on their pipelines. As of March 31, 2022, our future minimum throughput payments totaled $101.6 million, with $35.3 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our pipeline commitments and timing of our expected pipeline commitments payments.

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. As of March 31, 2022, our asset retirement obligations were $29.9 million, of which we expect to settle $0.2 million during the next year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our asset retirement obligations and timing of our expected asset retirement obligations payments.

Other Commitments

We have noncancelable agreements for product storage, railcar spurs, real estate and subsidy payments. As of March 31, 2022, our commitment obligations were $31.4 million, with $12.1 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our other commitments and timing of our expected commitment payments.

Cash Flows

The following table summarizes the sources (uses) of our cash flows from continuing operations for the periods indicated: 
  Year Ended March 31,
Cash Flows Provided by (Used in): 2019 2018 2017
  (in thousands)
Operating activities, before changes in operating assets and liabilities $263,513
 $176,052
 $159,613
Changes in operating assets and liabilities 44,001
 (122,423) (257,413)
Operating activities-continuing operations $307,514
 $53,629
 $(97,800)
Investing activities-continuing operations $(392,286) $105,343
 $(264,265)
Financing activities-continuing operations $(793,920) $(390,445) $375,087

Contractual Obligations
Operating Activities-Continuing Operations.
The seasonality
Our contractual obligations primarily consist of our Liquids business has a significant effect on our cash flowspurchase commitments, outstanding debt principal and interest obligations, operating lease obligations, pipeline commitments, asset retirement obligations and other commitments.

Purchase Commitments

Our fixed-price and index-price commodity purchase commitments result from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows duecontracts we have entered into for which we expect the parties to higher cash requirements to fund increases in inventories,physically settle 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 business, we typically experience operating losses or lower operating income during our first and second quarters, ordeliver the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. The heating season runs through the six months ending March 31. The seasonal motor fuel blend during the third quarter of our fiscal year impacts the value of our gasoline inventory in our Refined Products and Renewables business and also represents a period when we build inventory into our system. We borrow under 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 valuefuture periods. As of inventory, accounts receivable and payables, due to increases and decreases in revenues and cost of sales. The increase

in net cash provided by operating activities during the year ended March 31, 2019 was2022, our purchase commitments totaled $10.1 billion, with $5.5 billion due primarily to fluctuations in the value of accounts receivable, inventory and accounts payable during the year ended March 31, 2019. The increase in net cash provided by operating activities during the year ended March 31, 2018 was due primarily to higher inventory as a result of the purchase of additional pipeline capacity allocations in our Refined Products and Renewables segment during the year ended March 31, 2017.

Investing Activities-Continuing Operations. Net cash used in investing activities was $392.3 million during the year ended March 31, 2019, compared to net cash provided by investing activities of $105.3 million during the year ended March 31, 2018. The increase in net cash used in investing activities was due primarily to:

an increase in capital expenditures from $133.8 million during the year ended March 31, 2018 to $455.6 million during the year ended March 31, 2019 due primarily to capital expenditures for expansion projects in our Water Solutions segment; and
a $297.0 million increase in cash paid for acquisitions during the year ended March 31, 2019.

These increases in net cash used in investing activities were partially offset by a $118.8 million decrease in payments to settle derivatives.

Net cash provided by investing activities was $105.3 million during the year ended March 31, 2018, compared to net cash used in investing activities of $264.3 million during the year ended March 31, 2017. The increase in net cash provided by investing activities was due primarily to:

a decrease in capital expenditures from $344.9 million during the year ended March 31, 2017 to $133.8 million during the year ended March 31, 2018 due primarily to capital expenditures for the Grand Mesa Pipeline and the purchase of additional pipeline capacity allocations during the year ended March 31, 2017;
a $201.0 million increase in proceeds from sales of assets due primarily to the sales of our previously held 50% interest in Glass Mountain and a portion of Sawtooth and an increase in proceeds from the sale of excess pipe in our Crude Oil Logistics segment during the year ended March 31, 2018 and the sales of TLP common units we owned and Grassland during the year ended March 31, 2017; and
a $16.9 million payment to terminate a development agreement during the year ended March 31, 2017 (see Note 16 to our consolidated financial statements included in this Annual Report).

These increases in net cash provided by investing activities were partially offset by a $63.3 million increase in payments to settle derivatives.

Financing Activities-Continuing Operations. Net cash used in financing activities was $793.9 million during the year ended March 31, 2019, compared to net cash used in financing activities of $390.4 million during the year ended March 31, 2018. The increase in net cash used in financing activities was due primarily to:

an increase in repurchases and redemptions of our senior unsecured notes of $250.4 million during the year ended March 31, 2019; and
a decrease of $202.7 million due to proceeds received from the sale of our preferred units during the year ended March 31, 2018.

These increases in net cash used in financing activities were partially offset by an increase of $46.5 million in borrowings on the Revolving Credit Facility (net of repayments) during the year ended March 31, 2019.

Net cash used in financing activities was $390.4 million during the year ended March 31, 2018, compared to net cash provided by financing activities of $375.1 million during the year ended March 31, 2017. The increase in net cash used in financing activities was due primarily to:

$1.2 billion in proceeds from the issuance of the 2023 Notes and 2025 Notes during the year ended March 31, 2017;
an increase of $465.5 million for repayments and repurchases of all of our remaining outstanding senior secured notes and a portion of our Senior Unsecured Notes during the year ended March 31, 2018;

a decrease of $319.4 million in proceeds from the sale of our common units and preferred units during the year ended March 31, 2018;
an increase of $43.3 million in distributions paid to our general partners and common unitholders, preferred unitholders and noncontrolling interest owners during the year ended March 31, 2018; and
$26.4 million for the repurchase of a portion of our common units and warrants related to our 10.75% Class A Convertible Preferred Units (“Class A Preferred Units”) during the year ended March 31, 2018.

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

an increase of $1.2 billion in borrowings on the revolving credit facilities (net of repayments) during the year ended March 31, 2018;
the repayment of equipment loans totaling $41.7 million during the year ended March 31, 2017;
$30.8 million in debt issuance costs for the issuance of the 2023 Notes and 2025 Notes and the amendment and restatement of the Credit Agreement during the year ended March 31, 2017; and
a $25.9 million release of contingent consideration liabilities related to the termination of a development agreement during the year ended March 31, 2017 (see Note 16 to our consolidated financial statements included in this Annual Report).

Distributions Declared

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date.one year. See further discussion of our cash distribution policy in Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities included in this Annual Report.

On March 15, 2019, the board of directors of our general partner declared a distribution on the 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) for the three months ended March 31, 2019 of $4.7 million in the aggregate, which was paid to the holders of the Class B Preferred Units on April 15, 2019.

On April 24, 2019, the board of directors of our general partner declared a distribution of $0.39 per common unit to the unitholders of record on May 7, 2019. In addition, the board of directors of our general partner declared a distribution to the holders of the Class A Preferred Units of $4.0 million in the aggregate. The distributions were paid to the common unitholders on May 15, 2019 and to the holders of the Class A Preferred Units on May 10, 2019.

The initial distribution on our 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units will accumulate after the original issuance date until June 30, 2019 and will be payable on July 15, 2019, if declared.

For a further discussion of our distributions, see Note 108 to our consolidated financial statements included in this Annual Report.Report for information regarding our commodity purchase commitments and timing of our expected purchase commitments payments.

80



Debt Principal and Interest Obligations

As of March 31, 2022, our aggregate principal amount of outstanding debt was $3.4 billion, with $2.4 million due within one year. Our obligation for interest on the debt totaled $903.3 million, with $246.3 million due within one year, based on our outstanding balances and interest rates as of March 31, 2022. See Note 7 to our consolidated financial statements included in this Annual Report for information regarding our outstanding debt principal and interest obligations and timing of our expected payments.

Operating Lease Obligations

As of March 31, 2022, our undiscounted operating lease obligation was $145.9 million, with $46.6 million due within one year. See Note 15 to our consolidated financial statements included in this Annual Report for information regarding our lease obligations and timing of our expected lease payments.

Pipeline Commitments

Our pipeline commitments are noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on their pipelines. As of March 31, 2022, our future minimum throughput payments totaled $101.6 million, with $35.3 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our pipeline commitments and timing of our expected pipeline commitments payments.

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. As of March 31, 2022, our asset retirement obligations were $29.9 million, of which we expect to settle $0.2 million during the next year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our asset retirement obligations and timing of our expected asset retirement obligations payments.

Other Commitments

We have noncancelable agreements for product storage, railcar spurs, real estate and subsidy payments. As of March 31, 2022, our commitment obligations were $31.4 million, with $12.1 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our other commitments and timing of our expected commitment payments.

Contractual Obligations

The following table summarizes ourOur contractual obligations atprimarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, pipeline commitments, asset retirement obligations and other commitments.

Purchase Commitments

Our fixed-price and index-price commodity purchase commitments result from contracts we have entered into for which we expect the parties to physically settle and deliver the inventory in future periods. As of March 31, 2019 for2022, our fiscal years ending thereafter:
    Years Ending March 31,  
  Total 2020 2021 2022 2023 2024 Thereafter
  (in thousands)
Principal payments on long-term debt:              
Expansion capital borrowings $275,000
 $
 $
 $275,000
 $
 $
 $
Working capital borrowings 896,000
 
 
 896,000
 
 
 
Senior unsecured notes 996,458
 
 
 
 
 607,323
 389,135
Other long-term debt 5,331
 648
 4,683
 
 
 
 
Interest payments on long-term debt:              
Revolving Credit Facility (1) 146,419
 56,315
 56,315
 33,789
 
 
 
Senior unsecured notes 370,755
 69,384
 69,384
 69,384
 69,384
 69,384
 23,835
Other long-term debt 319
 210
 109
 
 
 
 
Letters of credit 143,360
 
 
 143,360
 
 
 
Future minimum lease payments under noncancelable operating leases 432,295
 127,718
 105,697
 83,595
 54,599
 18,841
 41,845
Future minimum throughput payments under noncancelable agreements (2) 43,203
 43,203
 
 
 
 
 
Construction commitments (3) 29,747
 29,747
 
 
 
 
 
Fixed-price commodity purchase commitments:              
Crude oil 60,227
 60,227
 
 
 
 
 
Natural gas liquids 5,298
 5,033
 265
 
 
 
 
Index-price commodity purchase commitments (4): 

            
Crude oil (5) 3,110,615
 1,703,112
 526,420
 411,071
 269,990
 200,022
 
Natural gas liquids 565,212
 564,013
 1,199
 
 
 
 
Total contractual obligations $7,080,239
 $2,659,610
 $764,072
 $1,912,199
 $393,973
 $895,570
 $454,815
(1)The estimated interest payments on the Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2019.purchase commitments totaled $10.1 billion, with $5.5 billion due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for additional information on the Credit Agreement.
(2)We have executed noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement, 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. A third party has agreed to assume all rights and privileges and to be fully responsible for any minimum shipping fees due for actual shipments that are less than our allotted capacity related to $30.0 million of the fiscal year 2020 amount under a definitive agreement we signed during the three months ended June 30, 2018. See Note 9 and Note 13 to our consolidated financial statements included in this Annual Report for additional information.
(3)At March 31, 2019, the construction commitments relate to three new towboats and four new barges currently being built.
(4)Index prices are based on a forward price curve at March 31, 2019. A theoretical change of $0.10 per gallon of natural gas liquids in the underlying commodity price at March 31, 2019 would result in a change of $102.6 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel of crude oil in the underlying commodity price at March 31, 2019 would result in a change of $58.4 million in the value of our index-price crude oil purchase commitments. See Note 9 to our consolidated financial statements included in this Annual Report for further detail of the commitments.
(5)Our crude oil index-price purchase commitments exceed our crude oil index-price sales commitments (see Note 9 to our consolidated financial statements included in this Annual Report) 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.


Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the letters of credit discussed in Note 8 to our consolidated financial statements included in this Annual Report for information regarding our commodity purchase commitments and timing of our expected purchase commitments payments.

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Debt Principal and Interest Obligations

As of March 31, 2022, our aggregate principal amount of outstanding debt was $3.4 billion, with $2.4 million due within one year. Our obligation for interest on the operating leases discussed in debt totaled $903.3 million, with $246.3 million due within one year, based on our outstanding balances and interest rates as of March 31, 2022. See Note 97 to our consolidated financial statements included in this Annual Report.Report for information regarding our outstanding debt principal and interest obligations and timing of our expected payments.

Operating Lease Obligations

As of March 31, 2022, our undiscounted operating lease obligation was $145.9 million, with $46.6 million due within one year. See Note 15 to our consolidated financial statements included in this Annual Report for information regarding our lease obligations and timing of our expected lease payments.

Pipeline Commitments

Our pipeline commitments are noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on their pipelines. As of March 31, 2022, our future minimum throughput payments totaled $101.6 million, with $35.3 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our pipeline commitments and timing of our expected pipeline commitments payments.

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. As of March 31, 2022, our asset retirement obligations were $29.9 million, of which we expect to settle $0.2 million during the next year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our asset retirement obligations and timing of our expected asset retirement obligations payments.

Other Commitments

We have noncancelable agreements for product storage, railcar spurs, real estate and subsidy payments. As of March 31, 2022, our commitment obligations were $31.4 million, with $12.1 million due within one year. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our other commitments and timing of our expected commitment payments.

Cash Flows

The following table summarizes the sources (uses) of our cash flows from continuing operations for the periods indicated: 
Year Ended March 31,
Cash Flows Provided by (Used in):202220212020
(in thousands)
Operating activities, before changes in operating assets and liabilities$342,362 $295,301 $342,736 
Changes in operating assets and liabilities(136,516)10,462 39,690 
Operating activities-continuing operations$205,846 $305,763 $382,426 
Investing activities-continuing operations$(212,408)$(221,493)$(1,737,620)
Financing activities-continuing operations$5,555 $(100,376)$978,833 

Operating Activities-Continuing Operations. The seasonality of our Liquids Logistics segment 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 segment, 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
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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 year ended March 31, 2022 was due primarily to fluctuations in the value of accounts receivable and accounts payable, increased inventory valuations and higher interest expense during the year ended March 31, 2022. The decrease in net cash provided by operating activities during the year ended March 31, 2021 was due primarily to fluctuations in the value of accounts receivable, inventories and accounts payable during the year ended March 31, 2021.

Investing Activities-Continuing Operations. Net cash used in investing activities was $212.4 million during the year ended March 31, 2022, compared to net cash used in investing activities of $221.5 million during the year ended March 31, 2021. 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 217 to our consolidated financial statements included in this Annual Report);
a decrease in capital expenditures from $186.8 million (includes payment of amounts accrued as of March 31, 2020) during the year ended March 31, 2021 to $142.4 million (includes payment of amounts accrued as of March 31, 2021) during the year ended March 31, 2022 due primarily to fewer expansion projects in our Water Solutions segment; and
proceeds of $18.5 million from certain asset sales during the year ended March 31, 2022 (see Note 4 to our consolidated financial statements included in this Annual Report).

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

a $71.7 million increase in payments to settle derivatives; and
total proceeds of $43.2 million from the sale of certain permits, land and a saltwater disposal facility to a third-party during the year ended March 31, 2021 (see Note 17 to our consolidated financial statements included in this Annual Report).

Net cash used in investing activities was $221.5 million during the year ended March 31, 2021, compared to net cash used in investing activities of $1.7 billion during the year ended March 31, 2020. The decrease in net cash used in investing activities was due primarily to:

a $1.3 billion in cash paid for acquisitions and investments in unconsolidated entities during the year ended March 31, 2020; and
a discussiondecrease in capital expenditures from $555.7 million (includes payment of amounts accrued as of March 31, 2019) during the year ended March 31, 2020 to $186.8 million (includes payment of amounts accrued as of March 31, 2020) during the year ended March 31, 2021 due primarily to expansion projects in our Delaware Basin system in the Water Solutions segment during the year ended March 31, 2020.

These decreases in net cash used in investing activities were partially offset by a $167.1 million increase in payments to settle derivatives.

Financing Activities-Continuing Operations. Net cash provided by financing activities was $5.6 million during the year ended March 31, 2022, compared to net cash used in financing activities of $100.4 million during the year ended March 31, 2021. The decrease in net cash used in financing activities was due primarily to:

an increase of $1.6 billion in borrowings on the revolving credit facilities (net of repayments) during the year ended March 31, 2022;
the repayment and termination of our $250.0 million term credit agreement in February 2021;
a decrease of $144.6 million in distributions paid to our general partners and common unitholders, preferred unitholders and noncontrolling interest owners during the year ended March 31, 2022 due primarily to the reduction and subsequent suspension of the lease accounting standard we adopted effective April 1, 2019.quarterly common unit and preferred unit distributions;
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$93.4 million in contingent consideration payments during the year ended March 31, 2021 due to installment payments related to the Mesquite acquisition;
a make-whole fee of $55.6 million related to the termination of our term credit agreement in February 2021;
a decrease of $50.6 million in debt issuance costs related to the termination of our term credit agreement and the issuance of the 2026 Senior Secured Notes in February 2021; and
a decrease of $32.6 million paid in cash to repurchase a portion of our Senior Unsecured Notes during the year ended March 31, 2022.

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

$2.05 billion in proceeds from the issuance of the 2026 Senior Secured Notes during the year ended March 31, 2021; and
proceeds of $45.0 million for an equipment loan that is secured by certain of our barges and towboats during the year ended March 31, 2021.

Net cash used in financing activities was $100.4 million during the year ended March 31, 2021, compared to net cash provided by financing activities of $978.8 million during the year ended March 31, 2020. The decrease in net cash provided by financing activities was due primarily to:

a decrease of $1.8 billion in borrowings on the revolving credit facilities (net of repayments) during the year ended March 31, 2021;
$622.4 million in net proceeds from the issuance of the 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and the Class D Preferred Units during the year ended March 31, 2020;
$450.0 million in proceeds from the issuance of the 2026 Notes during the year ended March 31, 2020;
$115.8 million paid in cash to repurchase a portion of our Senior Unsecured Notes during the year ended March 31, 2021;
a make-whole fee of $55.6 million related to the termination of our term credit agreement in February 2021; and
an increase of $50.6 million in debt issuance costs related to the termination of our term credit agreement and the issuance of the 2026 Senior Secured Notes in February 2021.

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

$2.05 billion in proceeds from the issuance of the 2026 Senior Secured Notes during the year ended March 31, 2021;
$265.1 million in payments for the redemption of the 10.75% Class A Convertible Preferred Units during the year ended March 31, 2020; and
a decrease of $99.3 million in distributions paid to our general partners and common unitholders, preferred unitholders and noncontrolling interest owners during the year ended March 31, 2021 due primarily to the reduction and subsequent suspension of the quarterly common unit and preferred unit distributions.

Guarantor Summarized Financial Information

NGL Energy Partners LP (parent) and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes (see Note 7 to our consolidated financial statements included in this Annual 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 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
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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
March 31, 2022
(in thousands)
ASSETS:
Current assets$1,544,169 
Noncurrent assets (1)(2)$4,496,111 
LIABILITIES AND EQUITY (3):
Current liabilities$1,276,612 
Noncurrent liabilities$3,524,560 
Class D Preferred Units$551,097 
(1)    Excludes $3.3 million of net intercompany payables due from NGL Energy Partners LP (parent) and the Guarantor Subsidiaries to the non-guarantor subsidiaries.
(2)    Includes $1.9 billion of goodwill and intangible assets.
(3)    There are no noncontrolling interests held at the co-issuers or Guarantor Subsidiaries.

Statement of operations information:
NGL Energy Partners LP (Parent) and Guarantor Subsidiaries
Twelve Months Ended
March 31, 2022
(in thousands)
Revenues$7,945,689 
Operating income$80,096 
Loss from continuing operations$(188,236)
Net loss (1)$(188,236)
Loss from continuing operations allocated to common unitholders$(292,765)
(1)    There are no noncontrolling interests held at the co-issuers or Guarantor Subsidiaries.

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Environmental Legislation

See Part I, Item 1–“Business–Government RegulationRegulation–Greenhouse Gas RegulationRegulation” 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 consolidated financial statements included in this Annual Report.


Critical Accounting PoliciesEstimates

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 the following more critical judgment areas in the application of our 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.

Revenue Recognition

Effective April 1, 2018, 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. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer. A contract’s transaction price is allocated to each distinct performance obligation in the contract and is recognized as revenue when, or as, the performance obligation is satisfied. Our revenue contracts in scope under ASC 606 primarily have a single performance obligation. The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgment and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers and the relative stand-alone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can vary from those judgments and assumptions. See Note 15 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain physical contracts that qualify for 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.

We have not designated any financial instruments as hedges for accounting purposes. 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements and are reported within cost of sales on the consolidated statements of operations, along with related settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery

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obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Impairment of Long-Lived Assets

We evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. We compare the carrying value of the long-lived asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset’s unamortized cost may not be recoverable due to impairment, we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of a long-lived asset would increase costs and expenses at that time.

We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary.

Impairment of Goodwill

Goodwill is subjectThe goodwill relating to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quartereach of our fiscal year, and more frequently ifreporting units is tested for impairment annually as well as when an event or change in circumstances warrant. For purposes of goodwillindicates an impairment testing, assets are grouped into “reporting units”. A reporting unit is either an operating segment or a component of an operating segment, depending on how similar the components of the operating segment are to each other in terms of operational and economic characteristics.may have occurred. For each reporting unit, we perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying amount,value, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’s fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, an impairment loss is recognized to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value, limited to the total amount of goodwill for the reporting unit. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. During the years ended March 31, 2021 and 2020, we recorded goodwill impairments of $237.8 million and $250.0 million, respectively. We did not record a chargegoodwill impairment during the year ended March 31, 2022. See Note 5 to earnings may be required to reduceour consolidated financial statements included in this Annual Report for a further discussion of our goodwill impairment assessment.

Impairment of Long-Lived Assets

We evaluate the carrying value of goodwillour long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans as well as external factors such as industry and economic trends. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates. If the carrying value is not recoverable, an impairment loss is measured as the excess of the asset’s carrying value over its impliedestimated fair value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. We monitor the markets for our productsSee Note 4 and services, in addition to the overall market, to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value. See Note 6 to our consolidated financial statements included in this Annual Report for a further discussion of our goodwill impairment assessment.impairments of long-lived assets.
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Asset Retirement Obligations

We have contractual and regulatory obligations at certain facilitiesevaluate our investments in unconsolidated entities for which we have to perform remediation, dismantlement,impairment whenever events or removal activities when the assets are retired. We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determinechanges in circumstances indicate, in management’s judgment, that the fair value of such investment may have experienced a liability, we must make certain estimatesdecline to less than its carrying value and assumptions including, amongthe decline is other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Our consolidated balance sheet at March 31, 2019 includes a liability of $9.7 million related to asset retirement obligations, which is reported within other noncurrent liabilities.than temporary.

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.

Depreciation and Amortization Methods and Estimated Useful Lives of Property, Plant and Equipment and Intangible Assets

Depreciation and amortization expense is the systematic write-off of the cost of our property, plant and equipment (net of residual or salvage value, if any) and the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate our property, plant and equipment and amortize the majority of our intangible assets using the straight-line method, which results in our recording depreciation and amortization expense evenly over the estimated life of the individual asset. The estimate of depreciation and amortization expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipment in service or acquire intangible assets, we develop assumptions about the useful economic lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation and amortization expense prospectively.prospectively and have a material impact on our results of operations. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, changes in expected salvage values or changes in customer attrition rates. See Note 2, Note 4 and Note 6 to our consolidated financial statements included in this Annual Report for a further discussion.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for normal purchase and normal sale transactions that are expected to result in physical delivery. Changes in the fair value are recorded within revenue (for sales contracts) or cost of sales (for purchase contracts) in our consolidated statements of operations. We determine the fair value of our exchange traded derivative financial instruments utilizing publicly available prices, and for non-exchange traded derivative financial instruments, we utilize pricing models for similar instruments including publicly available prices and forward curves generated from a compilation of data gathered from third parties. Actual amounts could vary materially from estimated fair values due to changes in market prices. In addition, changes in the methods or assumptions used to determine the fair value of our derivative financial instruments could have a material effect on our consolidated financial statements. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk to see the impact of a 10% increase in the underlying commodity value and Note 2 and Note 10 to our consolidated financial statements included in this Annual Report for a further discussion of our derivative financial instruments.

Revenue Recognition

Our Water Solutions segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our corresponding performance obligation, and the difference in timing of revenue recognition and billings results in contract assets and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management including volume and forecasted production information. Changes in these assumptions or a contract modification could have a material effect on the amount of variable consideration recognized as revenue. See Note 14 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies.

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 largest asset retirement obligations involve the abandonment or removal of pipelines and saltwater and freshwater disposal wells. We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. Most of these retirement obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. These estimates and assumptions are very subjective and can vary
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over time. Our consolidated balance sheet at March 31, 2022 includes a liability of $29.9 million related to asset retirement obligations, which is reported within other noncurrent liabilities.

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.

Acquisitions

To determine if a transaction should be accounted for as a business combination or an acquisition of assets, we first calculate the relative fair values of the assets acquired. If substantially all of the relative fair value is concentrated in a single asset or group of similar assets, or if not but the transaction does not include a significant process (does not meet the definition of a business), we record the transaction as an acquisition of assets. For acquisitions of assets, the purchase price is allocated based on the relative fair values. For an acquisition of assets, goodwill is not recorded. All other transactions are recorded as business combinations.

Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. For a business combination, the excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but instead is evaluated for impairment at least annually. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination.

Inventories

Our inventories consist of crude oil, natural gas liquids, gasoline, diesel, ethanol and biodiesel. 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. At the end of each fiscal year, we also perform a “lower of cost or net realizable value” analysis; if the cost basis of the inventories would not be recoverable based on the net realizable value at the end of the year, we reduce the book value of the inventories to the recoverable amount. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or net realizable value write-down if we expect the net realizable value to recover by our fiscal year end. The net realizable values of these commodities change on a daily basis as supply and demand conditions change. We are unable to control changes in the net realizable value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that net realizable values will recover sufficiently by our fiscal year end.


Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The awards may also vest upon a change of control, at the discretion of the board of directors of our general partner.

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. 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.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

A significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of our fixed-rate debt but do not impact its cash flows.

The Revolving CreditABL Facility is variable-rate debt with interest rates that are generally indexed to bankthe Wall Street Journal prime rate or LIBOR interest rates.rate (or successor rate, which has since been determined to be an adjusted forward-looking term rate based on the secured overnight financing rate). At March 31, 2019,2022, we had $1.2 billion$116.0 million of outstanding borrowings under the Revolving CreditABL Facility at a weighted average interest rate of 4.39%4.64%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.5$0.1 million, based on borrowings outstanding at March 31, 2019.2022.

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

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit policy, respectively.policy. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At March 31, 2019, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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

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

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled. See “Critical Accounting Estimates” above for a discussion of how we determine the fair value of our financial derivative instruments.


The following table summarizes the hypothetical impact on the March 31, 20192022 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 (Water Solutions segment)$(4,838)
Crude oil (Crude Oil Logistics segment)$(8,612)
Propane (Liquids Logistics segment)$532 
Butane (Liquids Logistics segment)$(3,026)
Refined Products (Liquids Logistics segment)$(2,598)
Other Products (Liquids Logistics segment)$4,106 
 
Increase
(Decrease)
To Fair Value
Crude oil (Crude Oil Logistics segment)$(10,311)
Propane (Liquids segment)$773
Other products (Liquids segment)$(4,175)
Gasoline (Refined Products and Renewables segment)$(5,715)
Diesel (Refined Products and Renewables segment)$(14,787)
Ethanol (Refined Products and Renewables segment)$(4,730)
Biodiesel (Refined Products and Renewables segment)$265
Canadian dollars (Liquids segment)$461


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 aboutChanges 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 actively quoted markets, quoted prices in less active marketsour credit policy. Credit risk is monitored daily and we try to 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 market fundamental analysis.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;
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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.

At March 31, 2022, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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Item 8.    Financial Statements and Supplementary Data

Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the reportsreport of Grant Thornton LLP, our independent registered public accounting firm, are incorporated by reference into this Item 8.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure 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 thatthe 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 (“SEC”) 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 March 31, 2019.2022. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2019,2022, such disclosure controls and procedures were effective to provide the reasonable assurance described above.effective.

Management’s Report on Internal Control Over Financial Reporting

The management of our Delaware limited partnership (the “Partnership”) and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO framework.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2019.

2022.

Our internal control over financial reporting as of March 31, 20192022 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report, which appears in Part IV, Item 15–“Exhibits, Financial Statement Schedulesbelow in this section of the Annual Report.


Changes in Internal Control Over Financial Reporting

Other than changes that have resulted or may result from our business combinations during the year ended March 31, 2019, as discussed below, thereThere 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 March 31, 20192022 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on internal control over financial reporting
We closed several business combinations duringhave audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2019, as described in Note 4 to2022, and our consolidatedreport dated June 6, 2022 expressed an unqualified opinion on those financial statementsstatements.

Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in this Annual Report. At this time, we continuethe accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to evaluateexpress an opinion on the business andPartnership’s internal controls and processes of these acquired businesses and are making various changes to their operating and organizational structurecontrol over financial reporting based on our business plan.audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the processcircumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of implementing our internal control structure over these acquired businesses. We expectfinancial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that our evaluation(1) pertain to the maintenance of records that, in reasonable detail, accurately and integration efforts relatedfairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to those combined operations will continue into future fiscal quarters.permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
June 6, 2022


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Item 9B.    Other Information

None.

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Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections


Not applicable.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Board of Directors of our General Partner

NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

The board of directors of our general partner currently has eight members. The board of directors of our general partner has determined that Mr. James C. Kneale,M. Collingsworth, Mr. Stephen L. Cropper, Mr. Bryan K. Guderian and Mr. James M. CollingsworthDerek S. Reiners satisfy the New York Stock Exchange (“NYSE”) and SECSecurities and Exchange Commission (“SEC”) independence requirements. The NYSE does not require a listed publicly traded limited partnership like usNGL to have a majority of independent directors on the board of directors of ourits general partner. In addition, we are not required to have a nominating and corporate governance committee.

In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

experience in business, government, education, technology or public interests;
high-level managerial experience in large organizations;
breadth of knowledge regarding our business and industry;
specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
moral character and integrity;
commitment to our unitholders’ interests;
ability to provide insights and practical wisdom based on experience and expertise;
ability to read and understand financial statements; and
ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.


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Directors and Named Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Named executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The following table summarizes information regarding the directors of our general partner and our named executive officers as of May 28, 2019. 
June 1, 2022. 
NameAgePosition with NGL Energy Holdings LLC
H. Michael Krimbill6568Chief Executive Officer and Director
Robert W. Karlovich IIILinda J. Bridges4238Executive Vice President and Chief Financial Officer
John A. Ciolek58Executive Vice President, Strategic Initiatives
Kurston P. McMurray4750Executive Vice President and General Counsel and Secretary
Lawrence J. Thuillier4851Chief Accounting Officer
Shawn W. Coady5760Director
James M. Collingsworth6467Director
Stephen L. Cropper6972Director
Bryan K. Guderian5962Director
James C. Kneale67Director
John T. Raymond4851Director
L. John Schaufele IVDerek S. Reiners3651Director
Randall S. Wade52Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. From February 2007 through September 2010, Mr. Krimbill managed private investments. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007, Williams Partners L.P. from 2007 to September 2012, and Pacific Commerce Bank from January 2011 to March 2015.

Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill also brings financial expertise to the board, including his prior service as a chief financial officer. Mr. Krimbill’s experience serving on other public company boards is also a valuable asset to our board of directors.

Robert W. Karlovich IIILinda J. Bridges. Mr. KarlovichMs. Bridges has served as our Executive Vice President and Chief Financial Officer since February 2016.September 30, 2021. Ms. Bridges served as our Senior Vice President, Finance and Treasurer from April 2018 to September 2021. She joined the general partner in June 2016, as Vice President of Finance and Treasurer until she was promoted. Ms. Bridges spent nine years in the commercial division at the Bank of Oklahoma, holding various positions including Vice President - Energy Lending.

John A. Ciolek. Mr. Ciolek joined us in December 2019 and was appointed as our Executive Vice President, Strategic Initiatives, by the board of directors of our general partner in January 2020. Prior to joining NGL, Mr. KarlovichCiolek served as Chief Financial Officer of Targa Pipeline Partners, a subsidiary of Targa Resources Partners, LP,Managing Director in the Oil and Gas Group at Credit Suisse Securities LLC (“Credit Suisse”) from February 2015 through February 2016, and as Senior Vice President of Commercial and Business Development for Targa Resources Partners, LP from NovemberAugust 2015 to February 2016. Mr. KarlovichOctober 2019. Before joining Credit Suisse, he served as the Head of the Midstream Franchise within J.P. Morgan’s North American Energy Group starting in various roles at Atlas Pipeline Partners, L.P. and its subsidiaries (“APL”), including most recently as Chief Financial Officer, from September 2006 to February 2015 when APL mergedMay 2011. He previously served for 14 years with Targa Resources Partners, LP. Mr. Karlovich served in various roles at Syntroleum Corporation from February 2004 to September 2006. Prior to that, Mr. Karlovich worked at Arthur Andersen LLP and Grant Thornton LLP. Mr. Karlovich is a certified public accountant.Citigroup’s Global Energy Group.

Kurston P. McMurray. Mr. McMurray has served as our Executive Vice President and General Counsel and Secretary since October 2016. Mr. McMurray joined NGL in February 2015 as Vice President, Legal and Corporate Secretary. Prior to joining NGL, Mr. McMurray practiced law in the Tulsa, Oklahoma area since 1998 at firms including Moyers, Martin, Santee, Imel & Tetrick LLP. and Robinett & Osmond and was a founding shareholder of Kurston P. McMurray, PC and Wilkin/McMurray PLLC. Mr. McMurray’s private practice specialized in business transactions, real estate, construction, healthcare, banking, corporate governance, corporate management and commercial litigation.

Lawrence J. Thuillier. Mr. Thuillier has served as our Chief Accounting Officer since January 2016. Prior to joining NGL, Mr. Thuillier served in various roles at Eagle Rock Energy Partners, L.P. from December 2007 through October 2015, most recently as Vice President of Financial Reporting and Corporate Controller. Mr. Thuillier served as Assistant Corporate
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Controller for Exterran Holdings, Inc. (formerly Universal Compression) from November 2006 through November 2007. Prior to that, Mr. Thuillier served in various roles at Deloitte & Touche LLP, most recently as Audit Senior Manager.


Shawn W. Coady. Dr. Coady had served as our President and Chief Operating Officer, Retail Division, sincefrom April 2012 to March 2018, when we sold a portion of our Retail Propane segment to DCC LPG (“DCC”), and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. On March 30, 2018, Dr. Coady served as a resultan executive officer of the sale of a portion of our Retail Propane segment (see Note 17 to our consolidated financial statements includedDCC from April 2018 until his retirement in this Annual Report for a further discussion), resigned from his position as President and Chief Operating Officer, Retail Division, but will remain as a member of the board of directors of our general partner.December 2020. Dr. Coady served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), from March 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicksgas LLC, and the membership interests in Hicksgas LLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until the membership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National Propane Gas Association from 2004 to 2015 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.

Dr. Coady brings valuable operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

James M. Collingsworth. Mr. Collingsworth has served on the board of directors of our general partner since January 2015. Mr. Collingsworth previously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through January 2014. Prior to that, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior to joining Texaco, Mr. Collingsworth was director of feedstocks for Rexene Petrochemical Company from 1988 to 1991 and served in the MAPCO, Inc. organization from 1973 to 1988 in various capacities, including customer service and business development manager of the Mid-America and Seminole pipelines. Mr. Collingsworth served as a director of American Ethane Co. Mr. Collingsworth currently serves on the board of directors of Martin Midstream Partners L.P. and American Ethane Co.

Mr. Collingsworth brings a wealth of in-depth industry experience to the board. Mr. Collingsworth has worked in all facets of the midstream and petrochemical industry for more than 40 years.

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners, L.P. from 2000 through 2005. Since Mr. Cropper’s retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., Berry Petroleum Company, and Rental Car Finance Corp., a subsidiary of Dollar Thrifty Automotive Group.Group and Wawa Inc. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation and Wawa Inc.Corporation.

Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian currently serves as a Principal of BKG Consulting LLC, an energy related consulting firm. Mr. Guderian has served as Executive Vice President of Business Development of WPX Energy, Inc. (“WPX”) sincefrom February 2018.2018 until his retirement in January 2021. Mr. Guderian served as Senior Vice President of Business Development of WPX from October 2014 to February 2018 and as Senior Vice President of Operations of WPX from August 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian served as a director of Apco Oil & Gas International Inc., from 2002 to 2015 and as a director of Petrolera Entre Lomas S.A. from 2003 to 2015.

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

James C. Kneale. Mr. Kneale joined the board of directors of our general partner in May 2011. Mr. Kneale served as President and Chief Operating Officer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until

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his retirement in January 2010. After joining ONEOK in 1981, Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOK Partners, L.P. from 2006 until his retirement in January 2010.


Mr. Kneale brings extensive executive, financial and operational experience to the board. With nearly 30 years of experience in the natural gas liquids industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry.

John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group (“EMG”) of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

Mr. Raymond also currently serves as a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica EMG, LLC, Medallion Midstream, LLC Plains All American GP LLC,and PAA GP Holdings LLC, Tallgrass MLP GP LLC and Tallgrass Management, LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC.

Mr. Raymond brings extensive financial and industry experience to the board. As a director for other public companies, Mr. Raymond also provides cross board experience.

L. John Schaufele IV.Derek S. Reiners. Mr. SchaufeleReiners joined the board of directors of our general partnerpartners in February 2018.December 2019 and was appointed to serve on the Audit Committee. Mr. Schaufele has worked at EMG since 2011. Mr. Schaufele previously worked at a middle-market private equity investment firm and JPMorgan. Mr. SchaufeleReiners currently serves as the President of Contango Energy Capital LLC, a directorprivately held investment and consulting firm. Prior to that, Mr. Reiners served in various senior financial and accounting roles at ONEOK, Inc. and ONEOK Partners, L.P. from August 2009 to May 2019, including Senior Vice President and Chief Accounting Officer from August 2009 to December 2012, Senior Vice President, Chief Financial Officer from January 2013 to May 2017 and Senior Vice President, Finance and Treasurer from June 2017 to May 2019. Prior to joining ONEOK, Mr. Reiners was a partner at Grant Thornton LLP from August 2004 to July 2009. Mr. Reiners is a certified public accountant.

Mr. Reiners brings extensive executive, financial and operational experience to the board. With over ten years of Ascent Resources, LLC, Flat River Minerals Heritage NonOp Holdings, LLC, Heritage Minerals Holdings, LLC, Silver Creek Midstreamexperience in the natural gas liquids industry in numerous positions, Mr. Reiners provides valuable insight into our business and White Star Petroleum Holdings, LLC;industry.

Randall S. Wade. Mr. Wade has served on the board of directors of our general partner since February 2021. Mr. Wade is the President of EIG Global Energy Partners (“EIG”) and a member of its Investment and Executive Committees. He has broad involvement in the firm’s various activities including investments, investor relations, operations and strategic initiatives. Since joining EIG in 1996, Mr. Wade has filled various roles including Chief Operating Officer, head of the direct lending strategy, investment principal with coverage responsibility for Australia and an analyst for the oil and gas team. Prior to joining EIG, Mr. Wade was a Commercial Lending Officer for First Interstate Bank of Texas, where he was also previouslyresponsible for developing a director of Lighthouse Oil & Gas, Traverse Midstream and Utica Minerals Development, LLC. Mr. Schaufele received a B.S. in Business and Accounting from Washington & Lee University.middle-market loan portfolio.

Mr. SchaufeleWade brings extensive financial and industry experience to the board. With 15 years of experience in the energy sector, Mr. Schaufele provides valuable insight into our business.

Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors of our general partner. EMG NGL HC LLC has the right to designate two personsone person to serve on the board of directors of our general partner, and has designated John T. RaymondRaymond. EIG has the right to designate one person to serve on the board of directors of our general partner, and L. John Schaufele IV.has designated Randall S. Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and his brother Todd M. Coady) and the investors who formed the Partnership (“IEP Parties”) (which consists of certain entities controlled by H. Michael Krimbill, and two other investors) each have the right to designate one person to serve on the board of directors of our general partner. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman.chairman, although our chief executive officer, Mr. Krimbill, presides over the meetings.

The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors.directors regarding its respective risk oversight role.
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Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

retain and terminate our independent registered public accounting firm;
approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and
establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Mr. Collingsworth, Mr. Cropper, Mr. Guderian, and Mr. KnealeReiners currently serve on the audit committee, and Mr. KnealeReiners serves as the chairman. The board of directors of our general partner has determined that Mr. KnealeReiners is an “audit committee financial expert” as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE and Exchange Act rules.

Compensation Committee

The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include the following, among others:

establishing the general partner’s compensation philosophy and objectives;
approving the compensation of the Chief Executive Officer;Officer and other officers;
making recommendations to the board of directors with respect to the compensation of other officers and directors; and
reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based compensation plans.

Mr. Collingsworth, Mr. Cropper, and Mr. Guderian and Mr. Kneale currently serve on the compensation committee.committee, and Mr. Cropper serves as the chairman. The board of directors of our general partner has determined that Mr. Cropper, Mr. Collingsworth and Mr. KnealeGuderian are independent directors under applicable NYSE and Exchange Act rules. The NYSE does not require a listed publicly traded limited partnership to have a compensation committee consisting entirely of independent directors.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires our general partner’s board of directors and named executive officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of our common units and other equity securities with the SEC. Directors, named executive officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations by our directors and named executive officers, we believe that all reporting obligations of our general partner’s directors and named executive officers and our greater than 10% unitholders under Section 16(a) were satisfied during the year ended March 31, 2019, except for the forfeiture of units upon termination of Mr. Osterman’s employment related to the sale of virtually all of our remaining Retail Propane segment on July 10, 2018, which was delayed due to an administrative error and the acquisition of 95,333 common units by Highstar Capital IV, L.P. upon exercise of warrants on May 11, 2018 was reported late on a Form 4 filed on June 27, 2018.


Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controllerChief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate Controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

We make available free of charge, within the “Governance” section of our website at http://www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. KnealeReiners presides over these executive sessions.

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.

Item 11.    Executive Compensation

Compensation Discussion and Analysis

The year “2019”“2022” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2019.2022.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. The board of directors has formed a compensation committee to develop our compensation program and to determineapprove the compensation of ourthe Chief Executive Officer and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are also officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our “named executive officers” for fiscal year 20192022 were:

H. Michael Krimbill–Chief Executive Officer
Robert W. Karlovich III–Linda J. Bridges–Executive Vice President and Chief Financial Officer (effective September 30, 2021)
Lawrence J. Thuillier–Chief Accounting Officer
Kurston P. McMurray–Executive Vice President and General Counsel and Secretary
Vincent J. Osterman–John A. Ciolek–Executive Vice President, Strategic Initiatives
Robert W. Karlovich III–Former Executive Vice President Retail Propane Operations. Mr. Osterman resigned from employment in conjunction with the sale of virtually all of our remaining Retail Propane segment on July 10, 2018.and Chief Financial Officer (resigned effective September 30, 2021)


Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer’s contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

Our executive compensation program is designed to provide a total compensation package that allows us to:

Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;
individuals with the background and skills necessary to successfully execute our business strategies;
Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and
Reward success in reaching those goals.

Recent Achievements

Our compensation structure is designed to reward our officers for achieving above-market returns for our unitholders. Our achievements during the year ended March 31, 2019 included the following:

On July 10, 2018, we sold virtually all of our remaining Retail Propane segment for net proceeds of $889.8 million;unitholders; and
On February 28, 2019, we sold our South Pecos water disposal business for net proceeds of $232.2 million;Reward success in reaching those goals.
On November 30, 2018, we sold our Bakken saltwater disposal business for net proceeds of $85.0 million; and
On May 3, 2018, we sold our previously held interest in E Energy Adams, LLC for net proceeds of $18.6 million.
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Compensation Highlights

We paid cash bonuses to Mr. Krimbill, Mr. Karlovich and Mr. McMurray during fiscal year 2019, primarily due to their work related to the sale of virtually all of our remaining Retail Propane segment and our South Pecos and Bakken water disposal businesses.
The salaries of most of our named executive officers remain below the median of our benchmark peer group. This enables us to grant more performance-based compensation to maintain competitive total compensation packages and achieve a greater degree of alignment of pay and performance.

Factors Enhancing Alignment with Unitholder Interests

Majority of named executive officer pay is atAt risk incentive compensation based on annual financial performance and growth in unitholder value;
Equity-based incentives are the largest single component of officer compensation;
No excise tax gross-ups; and
Compensation committee engages an independent compensation adviser.

Compensation Setting Process
 
Our compensation program for our named executive officers supports our philosophy of pay-for-performance.
Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our other named executive officers, other than his own.
Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. During fiscal

year 2019,Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. In March 2021, the compensation committee received compensation advice and data from Pearl Meyer & Partners (“PM&P”). PM&P conducted a competitive review ofprovided advice and guidance regarding the principal components of compensation for our directors and market salary information for certain executive officers, including our named executive officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-term incentive plan design.senior vice president positions. The compensation committee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal year 2019:the following:

PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;
PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
Fees paid to PM&P by the Partnership during fiscal year 2019 were less than 1% of PM&P’s total revenue;
None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;
None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and
None of the PM&P consultants working on Partnership matters own Partnership interests.
PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;
PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
Fees paid to PM&P by the Partnership for the services provided in March 2021 were less than 1% of PM&P’s total revenue;
None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;
None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and
None of the PM&P consultants working on Partnership matters own Partnership interests.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committee considered the recommendations provided by PM&P in the process of designing the fiscal year 2019 compensation program.

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Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. The following table summarizes the primary elements of compensation in our executive compensation program: 
Objective Supported
ElementPrimary PurposeHow Amount Determined
Attract &

Retain
Motivate &
Pay for

Pay-for-
Performance
Unitholder

Alignment
Base Salary
ž Fixed income to compensate executive officers for their level of responsibility, expertise and experience
ž Based on competition in the marketplace for executive talent and abilities
X
Discretionary Cash Bonus Awards
ž Rewards achievement of specific annual financial and operational performance goals
ž Based on the named executive officer’s relative contribution to achieving or exceeding annual goalsthe ongoing business of the Partnership
XXX
ž Recognizes individual contributions to our performance
Long-Term Equity Incentive Awards
ž Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders
ž Based on the named executive officer’s expected contribution to long-term performance goals
XXX
ž Provides a forfeitable long-term incentive to encourage executive retention


Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.
Mr. Krimbill’s initialOur named executive officers are entitled to the following annual base salaries:
NameFiscal Year Ended
March 31, 2021
Base Salary Rate($)(1)
Fiscal Year Ended
March 31, 2022
Base Salary Rate($)(2)
H. Michael Krimbill625,000 625,000 
Linda J. Bridges— 500,000 
Lawrence J. Thuillier300,000 312,000 
Kurston P. McMurray500,000 500,000 
John A. Ciolek500,000 500,000 
Robert W. Karlovich III500,000 500,000 
(1)    Messrs. Thuillier and McMurray’s base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer’s expected individual contribution to our performance. At the request of Mr. Krimbill, the parties agreed that he should receive a lowerrates became effective March 28, 2021. All other named executive officers’ base salary rates were effective April 1, 2020, other than our otherMs. Bridges who was not serving as a named executive officers atofficer during the time because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, therelevant fiscal year.
(2)    Ms. Bridges base salary ofrate became effective with her appointment to Executive Vice President and Chief Financial Officer on September 30, 2021. Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. TheThuillier’s base salary of Mr. Krimbill was restored to $120,000rate became effective November 12, 2012. Effective July 1, 2014, the board of directors increased Mr. Krimbill’s salary to $350,000, in consideration of the fact that his salary was low relative to the benchmark peer group (and remains below the 25th percentile of the peer group). Effective April 1, 2018, Mr. Krimbill’s base salary was increased to $625,000, in consideration of the fact that his salary was low relative to the benchmark peer group.
on January 16, 2022. Mr. Karlovich’s base salary rate for the fiscal year was prorated through September 30, 2021, the date of $400,000 was negotiated prior to his joining our management team in February 2016. Mr. Karlovich’sresignation from employment. All other named executive officers’ base salary was increased to $430,000 in April 2017. On June 10, 2018, Mr. Karlovich’s salary was increased to $500,000, in consideration of the fact that his salary was low relative to the benchmark peer group.
Mr. Thuillier’s base salary of $250,000 was negotiated prior to his joining our management team in January 2016. In April 2017, Mr. Thuillier’s base salary was increased to $260,000. In April 2018, Mr. Thuillier’s base salary was increased to $268,000. Effective March 31, 2019, Mr. Thuillier’s base salary was increased to $270,000.
Mr. McMurray’s base salary of $250,000 was negotiated prior to his joining our management team in February 2015. Mr. McMurray’s base salary was increased to $300,000 in April 2017. Effectiverates were effective April 1, 2018, Mr. McMurray’s base salary was increased to $350,000. Effective March 31, 2019, Mr. McMurray’s base salary was increased to $375,000.2021.
Mr. Osterman’s initial base salary of $125,000 was negotiated at the time he joined our management team upon completion of our acquisition of Osterman Propane. Mr. Osterman’s salary was increased to $200,000 in January 2013, to $250,000 in July 2013 and increased to $315,000 effective April 2, 2017, in consideration of the fact that his salary was low relative to the benchmark peer group. Mr. Osterman resigned from employment in conjunction with the sale of virtually all of our remaining Retail Propane segment on July 10, 2018.

Discretionary Cash Bonus Awards

None of the named executive officers is subject to a formal cash bonus plan, and any cash bonuses are at the discretion of either the board of directors (in the case of Mr. Krimbill) or the compensation committee of the board of directors (in the case of the other named executive officers). Cashdirectors. During fiscal year 2022, cash bonuses of $1.0 million, $0.7 million and $0.7$0.3 million were paid to
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both Mr. Ciolek and Mr. McMurray and cash bonuses of $0.2 million were paid to both Ms. Bridges and Mr. Thuillier. Neither Mr. Krimbill nor Mr. Karlovich and Mr. McMurray, respectively,received a cash bonus during fiscal year 2019, primarily due to their work related to the sale of virtually all of our remaining Retail Propane segment and our South Pecos and Bakken water disposal businesses.2022.


Long-Term Equity Incentive Awards

CertainThe Partnership previously adopted a long-term incentive plan (“LTIP”), which allowed for the issuance of equity-based compensation. The LTIP expired with respect to future awards on May 10, 2021. Prior to expiring, on May 5, 2021, the compensation committee of our board of directors granted certain restricted units granted to the named executive officers, which vest in tranches, contingent only on the continued service of the recipient through the vesting date (the “Service Awards”). The following table summarizes Service Award units granted, vested and/or forfeited during fiscal year 2019 with respectsubject to the named executive officers:
  Unvested Units at       Unvested Units at
Name March 31, 2018 Units Granted Units Vested Units Forfeited March 31, 2019
H. Michael Krimbill (1) 200,000
 300,000
 (100,000) 
 400,000
Robert W. Karlovich III (2) 62,500
 25,000
 (25,000) 
 62,500
Lawrence J. Thuillier (3) 25,000
 21,551
 (21,551) 
 25,000
Kurston P. McMurray (4) 37,500
 20,000
 (15,000) 
 42,500
Vincent J. Osterman (5) 50,000
 
 
 (50,000) 
(1)
Mr. Krimbill vested in 100,000 Service Awards on July 9, 2018. He was granted 300,000 Service Awards on November 21, 2018, of which 75,000 vests on each of February 11, 2020, November 10, 2020, February 11, 2021 and November 12, 2021, respectively.
(2)Mr. Karlovich vested in 12,500 and 12,500 Service Awards on November 13, 2018 and February 12, 2019, respectively. He was granted 25,000 Service Awards on November 21, 2018, of which 12,500 vests on each of February 11, 2021 and November 12, 2021, respectively.
(3)
Mr. Thuillier vested in Service Awards of 11,551 on September 11, 2018, 5,000 on November 13, 2018 and 5,000 on February 12, 2019. He was granted 11,551 Service Awards on September 11, 2018 and 10,000 Service Awards on November 21, 2018, of which 5,000 vests on each of February 11, 2021 and November 12, 2021, respectively.
(4)Mr. McMurray vested in 7,500 and 7,500 Service Awards on November 13, 2018 and February 12, 2019, respectively. He was granted 20,000 Service Awards on November 21, 2018, of which 10,000 vests on each of February 11, 2021 and November 12, 2021, respectively.
(5)
Mr. Osterman forfeited 50,000 Service Awards on July 9, 2018 upon termination of his employment related to the sale of virtually all of our remainingRetail Propane segment on July 10, 2018. Mr. Osterman did not receive any Service Awards in fiscal year 2019 prior to the termination of his employment.

The Service Award units granted to the named executive officers were determined by reference to our peer group and the market-based benchmarks compiled by PM&P and were based on the named executive officers total compensation falling between the 25th and 50th percentile of the peer group.

The Service Award units granted on November 21, 2018 were intended as a discretionary bonus for performance during fiscal year ended March 31, 2018.

The following table summarizes the vesting dates of the unvested Service Award units at March 31, 2019 (as noted above, Mr. Osterman forfeited all unvested Service Award units in connection with the termination of his employment on July 10, 2018):
  Service Award Units Vesting By Fiscal Year Ending Unvested Units at
Name March 31, 2020 March 31, 2021 March 31, 2022 March 31, 2019
H. Michael Krimbill (1) 175,000
 150,000
 75,000
 400,000
Robert W. Karlovich III (2) 25,000
 25,000
 12,500
 62,500
Lawrence J. Thuillier (2) 10,000
 10,000
 5,000
 25,000
Kurston P. McMurray (3) 15,000
 17,500
 10,000
 42,500
(1)Mr. Krimbill’s Service Awards will vest as follows: For the fiscal year ending March 31, 2020, 100,000 of the units will vest on July 8, 2019 and 75,000 of the units will vest on February 11, 2020. For the fiscal year ending March 31, 2021, half of the units will vest on November 10, 2020 and February 11, 2021. For the fiscal year ending March 31, 2022, the units will vest on November 12, 2021.
(2)Mr. Karlovich’s and Mr. Thuillier’s Service Awards will vest as follows: For the fiscal year ending March 31, 2020, half of the units will vest on November 13, 2019 and the other half on February 11, 2020. For the fiscal year ending March 31, 2021, half of the units will vest on November 10, 2020 and February 11, 2021. For the fiscal year ending March 31, 2022, the units will vest on November 12, 2021.
(3)Mr. McMurray’s Service Awards will vest as follows: For the fiscal year ending March 31, 2020, half of the units will vest on November 13, 2019 and the other half on February 11, 2020. For the fiscal year ending March 31, 2021, 7,500 of the units will vest on

November 10, 2020 and 10,000 of the units will vest on February 11, 2021. For the fiscal year ending March 31, 2022, the units will vest on November 12, 2021.

Beginning in April 2015, our general partner granted units that vest contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other peer entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance“Service Awards”). These PerformanceSee “2022 Grants of Plan Based Awards” for details about the number of restricted Service Award units were granted to certain employees. Performance was to be calculated based onin fiscal year 2022 and the return on our commonrelevant vesting terms.

The following table summarizes Service Award units (including changes in the market price of the common units and distributions paidactivity for all outstanding Service Award grants during the performance period) relativefiscal year 2022 with respect to the returnsnamed executive officers:
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits VestedUnits ForfeitedMarch 31, 2022
H. Michael Krimbill (1)75,000 250,000 (137,500)— 187,500 
Linda J. Bridges (2)6,250 100,000 (31,250)— 75,000 
Lawrence J. Thuillier (3)5,000 55,000 (18,750)— 41,250 
Kurston P. McMurray (4)10,000 150,000 (47,500)— 112,500 
John A. Ciolek (5)12,500 150,000 (50,000)— 112,500 
Robert W. Karlovich III (6)12,500 150,000 — (162,500)— 
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022. He was granted 250,000 Service Awards on May 5, 2021.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022. She was granted 100,000 Service Awards on May 5, 2021.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022. He was granted 55,000 on May 5, 2021.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(6)    Mr. Karlovich was granted 150,000 Service Awards on May 5, 2021. He forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

The following table summarizes the commonvesting dates of unvested Service Award units of the other entities in the Index. During the three months ended Decemberat March 31, 2018, the compensation committee of the board of directors of our general partner terminated the Performance Award plan and all unvested outstanding Performance Awards units were canceled. Accordingly, as no replacement awards were granted, all previously unrecognized compensation cost was expensed as of the cancellation date.2022:

Units by Vesting DateUnvested Units at
NameNovember 14, 2022February 13, 2023November 15, 2023March 31, 2022
H. Michael Krimbill62,500 62,500 62,500 187,500 
Linda J. Bridges25,000 25,000 25,000 75,000 
Lawrence J. Thuillier13,750 13,750 13,750 41,250 
Kurston P. McMurray37,500 37,500 37,500 112,500 
John A. Ciolek37,500 37,500 37,500 112,500 
Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers, other than to Mr. McMurray, who is entitled to receive severance benefits pursuant to his employment agreement in the event of certain terminations of his employment (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”). The board of directors has the option to accelerate the vesting of the restricted unitsService Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of restricted unitsService Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the Outstanding“Outstanding Equity Awards at March 31, 2019”2022” table below (in the “Market Value of Service Award Units that Have Not Yet Vested” column).
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401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. For every dollar that employees contribute up to 1%4% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employees contribute between 1%4% and 6% of their eligible compensation (as defined in the plan). Our matching contributions prior to January 1, 2015 vest over fivean employee’s first two years and, effective January 1, 2015, our matching contributions vest over two years.of employment, subject to a participant’s continued service.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We provideoffer a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, vision, disability and life insurance.

Other Officers

Certain officers who have leadership roles within our individual business units,segments, but who are not executive officers, participate in formulaic bonus programs that are based on the performance of the individual business unitssegments with which they are involved. In most cases, similar programs were in place prior to our acquisition of the businesses, and we have left the programs substantially intact.

Competitive Review and Fiscal Year 2019 Compensation Program

During fiscal year 2019, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and compensation program design. In order to provide guidance to the compensation committee regarding competitive rates of compensation, PM&P collected pay data from the following sources:

Compensation surveys including data from published compensation surveys representative of other energy industry and broader general industry companies with revenues of between $1 billion and $6 billion; and
Peer group data including pay data from 10-K and proxy filings for a group of 18 publicly traded midstream oil & gas partnerships of similar size and scope to us.


Compensation Peer Group Companies
AmeriGas Partners LPNuStar Energy L.P.Martin Midstream Partners LP
Ferrellgas Partners LPTarga Resources Corp.Boardwalk Pipeline Partners, LP
Star Group, L.P.Buckeye Partners, L.P.Western Gas Partners LP
Suburban Propane Partners, L.P.Genesis Energy LPEnLink Midstream Partners, LP
ONEOK Partners, L.P.Crestwood Equity Partners LP
Williams Partners L.P.Magellan Midstream Partners LP
Enbridge Energy Partners, L.P.DCP Midstream Partners LP

PM&P defines “market” as the combination of survey data and peer group data. As described above, the compensation committee considered this data in establishing salaries for fiscal year 2019 and in determining the number of Service Award units to grant to the named executive officers.

Employment Agreements

We do not have employment agreements with any of our named executive officers, other than Mr. McMurray (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”).

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Internal Revenue Code of 1986, as amended.

Compensation Committee Report

The compensation committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on this review and discussion, the compensation committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this Annual Report. 
Members of the Compensation Committee:
Stephen L. Cropper (Chairman)
James M. Collingsworth
Bryan K. Guderian
James C. Kneale

Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of executive compensation, as the restricted units are designed to reward the executive officers based on the long-term performance of the Partnership. In combination with our risk management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

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Compensation Committee Interlocks and Insider Participation

During fiscal year 2019,2022, James M. Collingsworth, Stephen L. Cropper, and Bryan K. Guderian and James C. Kneale served on the compensation committee. None of these individuals is an employee or an officer of our general partner. As described under Part I, Item 13–“Transactions With Related Persons,” Mr. Guderian is an executive officer of WPX, and we entered into certain transactions with WPX during fiscal year 2019. Shawn W. Coady was an executive officer and is still a member of the board of directors of our general partner. Dr. Coady also serves on the board of directors of HOH, a family-owned company, and in this capacity Dr. Coady participates in the compensation setting process of the HOH board of directors.


Summary Compensation Table for 2019

The following table summarizes the compensation earned by our named executive officers for fiscal years 20172020 through 2019.2022. 
Name and Position  
Fiscal
Year
 
Salary
($)
 
Bonus
($)
 
Restricted
Unit
Awards (Service and Performance Awards) (1)
($)
 
All Other
Compensation (2)
($)
 
Total
($)
H. Michael Krimbill 2019 614,423
 1,000,000
 1,928,520
 13,886
 3,556,829
Chief Executive Officer 2018 350,000
 
 
 10,891
 360,891
  2017 350,000
 
 7,174,094
 10,463
 7,534,557
             
Robert W. Karlovich III 2019 483,846
 650,000
 142,405
 7,695
 1,283,946
Executive Vice President and 2018 428,846
 430,000
 711,291
 9,079
 1,579,216
Chief Financial Officer 2017 400,000
 
 809,985
 5,510
 1,215,495
             
Lawrence J. Thuillier 2019 267,693
 
 191,964
 9,639
 469,296
Chief Accounting Officer 2018 259,615
 
 414,525
 9,357
 683,497
  2017 250,000
 
 374,007
 43,469
 667,476
             
Kurston P. McMurray (3) 2019 348,077
 650,000
 113,924
 9,199
 1,121,200
Executive Vice President and 2018 298,077
 300,000
 426,774
 8,182
 1,033,033
General Counsel and Secretary           

             
Vincent J. Osterman (4) 2019 98,500
 
 
 32,323
 130,823
Former President, 2018 312,500
 
 569,032
 44,926
 926,458
Retail Propane Operations 2017 250,000
 
 1,662,027
 36,831
 1,948,858
Name and Position Fiscal
Year
Salary
($)
Bonus
($)
Restricted Unit
Awards
(Service Awards) (1)
($)
All Other
Compensation (2)
($)
Total
($)
H. Michael Krimbill2022625,000 — 537,500 15,719 1,178,219 
Chief Executive Officer2021625,000 — — 17,632 642,632 
2020625,000 1,500,000 1,000,011 11,019 3,136,030 
Linda J. Bridges (3)2022413,846 200,000 215,000 15,632 844,478 
Executive Vice President and
Chief Financial Officer
Lawrence J. Thuillier2022300,692 150,000 118,250 15,353 584,295 
Chief Accounting Officer2021270,000 150,000 — 14,849 434,849 
2020269,923 — 135,004 9,751 414,678 
Kurston P. McMurray2022495,192 250,000 322,500 3,863 1,071,555 
Executive Vice President and2021375,000 600,000 — 9,210 984,210 
General Counsel and Secretary2020374,039 500,000 100,012 8,857 982,908 
John A. Ciolek2022500,000 250,000 322,500 12,374 1,084,874 
Executive Vice President,2021500,000 — — 15,390 515,390 
Strategic Initiatives2020140,385 — 501,250 119 641,754 
Robert W. Karlovich III (4)2022276,923 — 322,500 6,907 606,330 
Executive Vice President and2021500,000 600,000 — 12,759 1,112,759 
Chief Financial Officer2020500,000 500,000 100,012 6,900 1,106,912 
(1)The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our common units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of Accounting Standards Codification (“ASC”) 718 Stock Compensation. For fiscal years 2018 and 2017, this column also includes the value of Performance Awards granted, prior to the termination of the Performance Award plan.
(2)The amounts in this column include matching contributions to our 401(k) plan. Amount for Mr. Thuillier for fiscal year 2017 includes moving expenses. Amounts for Mr. Osterman include propane provided to him and members of his family (valued for the purpose at the cost of the propane to NGL). The following table summarizes these amounts for Mr. Thuillier and Mr. Osterman:
(1)    The fair values of the restricted units shown in the table above were calculated in accordance with FASB Accounting Standards Codification (“ASC”) Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.
Name 
Fiscal
Year
 
401(k)
Match
 Moving Expenses Propane 
Total Other
Compensation
Lawrence J. Thuillier 2017 $5,721
 $37,748
 $
 $43,469
           
Vincent J. Osterman 2019 $3,758
 $
 $28,565
 $32,323
  2018 $6,273
 $
 $38,653
 $44,926
  2017 $5,721
 $
 $31,110
 $36,831
(2)    The amounts in this column include matching contributions to our 401(k) plan and taxable group term life insurance.
(3)Mr. McMurray was not a named executive officer prior to fiscal year 2018.
(4)Mr. Osterman resigned from employment in conjunction with the sale of virtually all of our remaining Retail Propane segment on July 10, 2018.
(3)     Ms. Bridges became Executive Vice President and Chief Financial Officer effective September 30, 2021, and thus was not a named executive officer prior to fiscal year 2022.
(4)    Mr. Karlovich resigned as Executive Vice President and Chief Financial Officer effective September 30, 2021.

Employment Agreement with Mr. McMurray

Mr. McMurray is party to an employment agreement with the Partnership, dated March 10, 2017. The agreement has a term of five years from the effective date, subject to automatic renewals for one-year periods thereafter unless either party

provides 60 days’ notice of non-renewal of the term. The agreement was renewed by its terms as of March 10, 2022. The agreement provides that Mr. McMurray will receive a base salary of no less than $250,000 per year and will be eligible to receive an annual bonus with respect to each fiscal year of the Partnership at a target of 100% of his base salary. Mr. McMurray is also entitled to receive annual awards of unvested units under the Partnership’s LTIP.

In the event that Mr. McMurray’s employment is terminated by the Partnership without “cause” (as defined in his agreement), provided that he executes a general release of claims, Mr. McMurray is entitled to receive (i) continued payment of his base salary for 12 months following the termination, (ii) the guaranteed unit awards that would have been paid or granted to Mr. McMurray had Mr. McMurray remained employed for an additional three years following his termination, and (iii) his target annual bonus for the performance year in which his termination occurs. Mr. McMurray would also be entitled to receive
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the severance benefits described in the foregoing sentence in the event that he voluntarily resigns due to a “constructive discharge,” which circumstances would include (1) a reduction of Mr. McMurray’s annual base salary below $250,000 (other than an across-the-board, pro rata reduction of no more than 10% applicable to all similarly situated executive officers of the Partnership) or the Partnership’s failure to provide Mr. McMurray’s elements of compensation, (2) the removal of Mr. McMurray from the position of Executive Vice President and General Counsel and Secretary without Mr. McMurray’s written consent, (3) any action by the Partnership that results in significant diminution of Mr. McMurray’s authority, power or responsibilities, or (4) the Partnership’s relocation of its principal place of business in Oklahoma to a location more than 50 miles from its current location. Mr. McMurray is subject to non-disclosure and intellectual property rights assignment obligations, and an obligation not to solicit customers, employees or consultants lasting during his employment and for a period of 12 months thereafter.

Restricted Unit Awards

During fiscal year 2019,2022, the compensation committee granted awards for which units vest at specified dates, contingent only onService Awards to the continued service of the recipient through the service date (the “Service Awards”).named executive officers.

20192022 Grants of Plan Based Awards Table

The following table summarizes the number of restricted Service Award units granted to our named executive officers, and their grant date fair values:
Name Grant Date 
Total Number of Service Award 
Units
 
Grant Date Fair Value of
Service Award Units
($)(1)
H. Michael Krimbill November 21, 2018
 300,000
 1,928,520
Robert W. Karlovich III November 21, 2018
 25,000
 142,405
Lawrence J. Thuillier September 11, 2018
 11,551
 135,002
  November 21, 2018
 10,000
 56,962
Kurston P. McMurray November 21, 2018
 20,000
 113,924
Vincent J. Osterman (2) 
 
 
NameGrant DateTotal Number of Service Award 
Units (#)
Grant Date Fair Value of
Service Award Units
($)(1)
H. Michael KrimbillMay 5, 2021250,000 537,500 
Linda J. BridgesMay 5, 2021100,000 215,000 
Lawrence J. ThuillierMay 5, 202155,000 118,250 
Kurston P. McMurrayMay 5, 2021150,000 322,500 
John A. CiolekMay 5, 2021150,000 322,500 
Robert W. Karlovich IIIMay 5, 2021150,000 322,500 
(1)The fair value
(1)    The fair values of the restricted Service Award units shown in the table above was calculated based on the closing market price of our common units on the grant dates, with adjustments made to reflect the fact that restricted units are not entitled to distributions during the vesting period.
(2)Mr. Osterman did not receive any restricted Service Award units in fiscal year 2019 prior to the termination of his employment on July 10, 2018.

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. The amounts reported in the table above for restricted units is the grant date fair value for financial reporting purposes underwere calculated in accordance with ASC Topic 718, Stock Compensation, and does not represent the amount actually realized by the named executive officer at vesting, which may be more or less than the amount reported in the table above.


For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.

The 2022 Service Awards vest and settle in common units. During fiscal year 2022, the compensation committee granted Service Awards to the named executive officers for which units vest in substantially equal installments on February 10, 2022, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service of the recipients through each such vesting date.

Outstanding Equity Awards at March 31, 20192022

The following table summarizes the number of unvested Service Awards outstanding and their fair values at March 31, 2019:2022:
  
Number of Service Award Units
that Have Not Yet Vested
 
Market Value of Service Award Units
that Have Not Yet Vested
Name (#)(1) ($)(2)
H. Michael Krimbill 400,000
 5,612,000
Robert W. Karlovich III 62,500
 876,875
Lawrence J. Thuillier 25,000
 350,750
Kurston P. McMurray 42,500
 596,275
Vincent J. Osterman (3) 
 
Number of Service Award Units
that Have Not Yet Vested
Market Value of Service Award Units
that Have Not Yet Vested
Name(#)(1)($)(2)
H. Michael Krimbill187,500 416,250 
Linda J. Bridges75,000 166,500 
Lawrence J. Thuillier41,250 91,575 
Kurston P. McMurray112,500 249,750 
John A. Ciolek112,500 249,750 
Robert W. Karlovich III (3)— — 
(1)Reflects Service Awards that have not vested and are held by each named executive officer.
(2)Calculated based on the closing market price of our common units at March 31, 2019 of $14.03. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.
(3)Mr. Osterman forfeited all outstanding equity awards in connection with the termination of his employment on July 10, 2018.

(1)    Reflects Service Awards that have not vested and are held by each named executive officer. The outstanding Service Awards units vest in substantially equal installments on November 14, 2022, February 13, 2023 and November 15, 2023.
2019(2)    Calculated based on the closing market price of our common units at March 31, 2022 of $2.22. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.
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(3)    Mr. Karlovich resigned effective September 30, 2021 resulting in the forfeiture of his Service Awards. As a result, Mr. Karlovich did not have any outstanding equity awards as of March 31, 2022.

2022 Units Vested

During fiscal year 2019,2022, certain of the restricted Service Awards vested. The following table summarizes the value of the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates.
Name 
Number of Service Award Units
Acquired on Vesting
(#)
 
Value Realized on Vesting
($)
H. Michael Krimbill (1) 100,000
 1,247,500
Robert W. Karlovich III (2) 25,000
 272,375
Lawrence J. Thuillier (3) 21,551
 243,952
Kurston P. McMurray (4) 15,000
 163,425
Vincent J. Osterman (5) 
 
NameNumber of Service Award Units
Acquired on Vesting
(#)
Value Realized on Vesting
($)
H. Michael Krimbill (1)137,500 379,500 
Linda J. Bridges (2)31,250 63,250 
Lawrence J. Thuillier (3)18,750 25,300 
Kurston P. McMurray (4)47,500 43,925 
John A. Ciolek (5)50,000 63,250 
Robert W. Karlovich III (6)— — 
(1)Mr. Krimbill vested in 100,000 Service Awards on July 9, 2018.
(2)Mr. Karlovich vested in 12,500 and 12,500 Service Awards on November 13, 2018 and February 12, 2019, respectively.
(3)
Mr. Thuillier vested in 11,551, 5,000 and 5,000 Service Awards on September 11, 2018
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards onFebruary 10, 2022.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022.
(6)    Mr. Karlovich forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

, November 13, 2018 and February 12, 2019, respectively.
(4)Mr. McMurray vested in 7,500 and 7,500 Service Awards on November 13, 2018 and February 12, 2019, respectively.
(5)Mr. Osterman did not vest in any Service Awards prior to the termination of his employment on July 10, 2018.

Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing common units. The following table summarizes the number of common units issued and the number of common units withheld for taxes:
NameNumber of Units
Issued
Number of Units
Withheld
Total
H. Michael Krimbill137,500 — 137,500 
Linda J. Bridges16,753 14,497 31,250 
Lawrence J. Thuillier10,489 8,261 18,750 
Kurston P. McMurray25,489 22,011 47,500 
John A. Ciolek50,000 — 50,000 
Name 
Number of Units
Issued
 
Number of Units
Withheld
 Total
Robert W. Karlovich III 13,870
 11,130
 25,000
Lawrence J. Thuillier 12,589
 8,962
 21,551
Kurston P. McMurray 8,099
 6,901
 15,000

Potential Payments Upon Termination or Change in Control

We do not provide any severance or change of control benefits to our named executive officers, other than Mr. McMurray, who is entitled to receive severance benefits for certain types of terminations (as described in more detail above under the heading, “Employment Agreement with Mr. McMurray”). In the event that Mr. McMurray’s employment had been

terminated as of March 31, 20192022 by the Partnership without “cause” or due to a “constructive discharge,” Mr. McMurray would have been entitled to receive the following amounts:
Cash Severance Value of Guaranteed Unit Awards Target Annual Bonus Total
$375,000
 $596,275
 $375,000
 $1,346,275

Cash SeveranceValue of Guaranteed Unit AwardsTarget Annual BonusTotal
$500,000 $249,750 $500,000 $1,249,750 

The board of directors has the option to accelerate the vesting of the restricted unitsService Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of restricted unitsService Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the Outstanding“Outstanding Equity Awards at March 31, 2019”2022” table above (in the “Market Value of Service Award Units that Have Not Yet Vested” column).


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Pay Ratio Disclosure

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information regarding the ratio of the annual total compensation of our Chief Executive Officer, Mr. Krimbill, to the median of the annual total compensation of our employees for our last fiscal year.

For the year ended March 31, 2019:2022:

The median of the annual total compensation of all employees (other than the Chief Executive Officer) was $46,408;$88,063; and
The annual total compensation of Mr. Krimbill, as reported in the Summary Compensation Table above, was $3,556,829.$1,178,219.

Based on the information for the year ended March 31, 2019,2022, the ratio of the annual total compensation of our Chief Executive Officer to the annual total compensation of our median employee was approximately 7713 to 1.

To determine our median employee, we identified each individual employed by us on January 1, 2019,2022, our determination date. As of that date, we had 1,210876 employees located in two countries. We identified the median employee by examining only base pay plus overtime for the period from January 1, 20182021 through December 31, 2018.2021. We included all employees, with the exception of threefour employees that work in Canada, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions or adjustments to any base pay plus overtime amounts. After identifying the median employee, we calculated the annual total compensation for the median employee using the same methodology we use to calculate total annual compensation for our named executive officers, as set forth in the Summary Compensation Table above.

This pay ratio is a reasonable estimate calculated in a manner consistent with SEC rules based on our payroll and employment records and the methodology described above. The SEC rules for identifying the median employee and calculating the pay ratio based on that employee’s annual total compensation allow companies to adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices. As such, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

Hedging of Partnership Common Units

Our Supplemental Trading Policy prohibits directors, named executive offices and other designated employees from engaging in hedging activities with respect to our common units.

Director Compensation

Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following cash compensation for his board service:

an annual retainer of $60,000;
an annual retainer of $10,000 for the chairmen of the audit and compensation committees; and
an annual retainer of $5,000 for each member of the audit and compensation committees other than the chairman.


Special committees are convened by the board of directors from time to time to review specific transactions. Compensation paid to the members of these committees varies depending on the transaction and the expected time commitment of the committee members.

Effective on March 29, 2019, the board of directors approved the following changes to the compensation for each director who is not an officer or employee of our general partner or its affiliates:

an annual retainer of $80,000;
an annual retainer of $20,000 for the chairman of the audit committee;
an annual retainer of $15,000 for the chairman of the compensation committee;
an annual retainer of $14,000 for each member of the audit committee other than the chairman; and
an annual retainer of $10,000 for each member of the compensation committee other than the chairman.

In addition, each director who is not an officer or employee of our general partner or its affiliates (with the exception of Dr. Coady) has been granted awards of restricted units. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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The following table summarizes the compensation earned during fiscal year 20192022 by each director who is not an officer or employee of our general partner or its affiliates:
NameFees Earned or
Paid in Cash
($)
Restricted Unit
Awards
($)(1)
Total
($)
Shawn W. Coady80,000 107,500 187,500 
James M. Collingsworth104,000 107,500 211,500 
Stephen L. Cropper109,000 107,500 216,500 
Bryan K. Guderian104,000 107,500 211,500 
Derek S. Reiners100,000 107,500 207,500 
Name 
Fees Earned or
Paid in Cash
($)
 
Restricted Unit
Awards
($)
 
Total
($)
Shawn W. Coady 40,000
 
 40,000
James M. Collingsworth 75,000
 45,569
 120,569
Stephen L. Cropper 85,000
 45,569
 130,569
Bryan K. Guderian 75,000
 45,569
 120,569
James C. Kneale 85,000
 45,569
 130,569
(1)    The amounts reflected in this column represent the grant date fair value of each director’s May 5, 2021 award of 50,000 restricted units, which were calculated in accordance with ASC Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report. See table below for discussion of the vesting of these grants.

Long-Term Equity Incentive Awards

The following table summarizes Service Award units granted and vestedactivity during fiscal year 20192022 with respect to each director who is not an officer or employee of our general partner or its affiliates:
  Unvested Units at     Unvested Units at
Name March 31, 2018 Units Granted Units Vested March 31, 2019
Shawn W. Coady (1) 40,000
 
 (20,000) 20,000
James M. Collingsworth (2) 24,000
 8,000
 (8,000) 24,000
Stephen L. Cropper (2) 24,000
 8,000
 (8,000) 24,000
Bryan K. Guderian (2) 24,000
 8,000
 (8,000) 24,000
James C. Kneale (3) 20,000
 8,000
 (8,000) 20,000
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits Vested (1)March 31, 2022 (2)
Shawn W. Coady4,000 50,000 (16,500)37,500 
James M. Collingsworth4,000 50,000 (16,500)37,500 
Stephen L. Cropper4,000 50,000 (16,500)37,500 
Bryan K. Guderian4,000 50,000 (16,500)37,500 
Derek S. Reiners4,000 50,000 (16,500)37,500 
(1)Dr. Coady vested in 20,000 Service Awards on July 9, 2018. These units were granted to Dr. Coady while in his role as our President and Chief Operating Officer, Retail Division. Dr. Coady was allowed to retain his unvested units when we sold a portion of our Retail Propane segment to DCC LPG (“DCC”). Dr. Coady did not receive any Service Awards in fiscal year 2019 prior to the termination of his employment.
(2)Mr. Collingsworth, Mr. Cropper and Mr. Guderian vested in 8,000 Service Awards on July 9, 2018. Mr. Collingsworth, Mr. Cropper and Mr. Guderian were granted 8,000 Service Awards on November 21, 2018, of which 4,000 vests on each of February 11, 2021 and November 12, 2021, respectively.
(3)Mr. Kneale vested in 4,000 Service Awards on November 13, 2018 and 4,000 Service Awards on February 12, 2019. Mr. Kneale was granted 8,000 Service Awards on November 21, 2018, of which 4,000 vests on each of February 11, 2021 and November 12, 2021, respectively.

(1)    4,000 Service Awards vested on November 12, 2021 and 12,500 Service Awards vested on February 10, 2022.

The following table summarizes(2)    12,500 Service Awards will vest on November 14, 2022, 12,500 Service Awards will vest on February 13, 2023 and 12,500 Service Awards will vest on November 15, 2023, subject to the vesting datescontinued service of the unvested Service Award units at March 31, 2019:
  Service Award Units Vesting By Fiscal Year Ending Unvested Units at
Name March 31, 2020 March 31, 2021 March 31, 2022 March 31, 2019
Shawn W. Coady (1) 20,000
 
 
 20,000
James M. Collingsworth (2) 12,000
 8,000
 4,000
 24,000
Stephen L. Cropper (2) 12,000
 8,000
 4,000
 24,000
Bryan K. Guderian (2) 12,000
 8,000
 4,000
 24,000
James C. Kneale (3) 8,000
 8,000
 4,000
 20,000
(1)Dr. Coady’s Service Awards will vest on July 8, 2019.
(2)Mr. Collingsworth’s, Mr. Cropper’s and Mr. Guderian’s Service Awards will vest as follows: For the fiscal year ending March 31, 2020, 8,000 of the units will vest on July 8, 2019 and 4,000 of the units will vest on February 11, 2020. For the fiscal year ending March 31, 2021, half of the units will vest on November 10, 2020 and February 11, 2021. For the fiscal year ending March 31, 2022, the units will vest on November 12, 2021.
(3)Mr. Kneale’s Service Awards will vest as follows: For the fiscal year ending March 31, 2020, half of the units will vest on July 8, 2019 and February 11, 2020. For the fiscal year ending March 31, 2021, half of the units will vest on November 10, 2020 and February 11, 2021. For the fiscal year ending March 31, 2022, the units will vest on November 12, 2021.

recipients through each such vesting date.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table summarizes the beneficial ownership, as of May 28, 2019,June 1, 2022, of our common units by:

each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;
each director of our general partner;
each named executive officer of our general partner; and
all directors and executive officers of our general partner as a group.
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Beneficial Owners 
Common Units
Beneficially
Owned
 
Percentage of
Common Units
Beneficially
Owned (1)
5% or greater unitholders (other than officers and directors):  
  
OppenheimerFunds, Inc. (2) 20,250,603
 16.08%
ALPS Advisors, Inc. (3) 10,867,760
 8.63%
     
Directors and named executive officers:  
  
Shawn W. Coady (4) 2,578,195
 2.05%
James M. Collingsworth (5) 108,620
 *
Stephen L. Cropper (6) 51,000
 *
Bryan K. Guderian 48,500
 *
Robert W. Karlovich III (7) 59,533
 *
James C. Kneale (8) 52,000
 *
H. Michael Krimbill (9) 2,382,820
 1.89%
Kurston P. McMurray (10) 28,594
 *
Vincent J. Osterman (11) 3,983,730
 3.16%
John T. Raymond (12) 226,634
 *
L. John Schaufele IV 
 *
Lawrence J. Thuillier (13) 32,368
 *
All directors and named executive officers as a group (12 persons) (14) 9,551,994
 7.58%
Beneficial OwnersCommon Units
Beneficially
Owned
Percentage of
Common Units
Beneficially
Owned (1)
5% or greater unitholders (other than officers and directors):  
Invesco Ltd. (2)19,717,009 15.09 %
EIG Neptune Equity Aggregator, L.P. (3)16,734,375 11.35 %
Directors and named executive officers:  
Linda J. Bridges (4)62,165 *
John A. Ciolek (5)194,764 *
Shawn W. Coady (6)2,614,695 2.00 %
James M. Collingsworth (7)352,370 *
Stephen L. Cropper (8)87,500 *
Bryan K. Guderian85,000 *
H. Michael Krimbill (9)4,127,518 3.16 %
Kurston P. McMurray (10)84,231 *
John T. Raymond50,000 *
Derek S. Reiners38,500 *
Lawrence J. Thuillier (11)60,319 *
Randall S. Wade— *
All directors and executive officers as a group (12 persons) (12)7,757,062 5.94 %
* Less than 1.0%

(1)    Based on 130,695,970 common units outstanding at June 1, 2022.
(1)Based on 125,966,868 common units outstanding at May 28, 2019.
(2)The mailing address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to OppenheimerFunds, Inc. is based upon its Schedule 13F filed with the SEC for the quarter ended March 31, 2019.
(3)The mailing address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, CO 80203. ALPS Advisors, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to ALPS Advisors, Inc. is based upon its Schedule 13F filed with the SEC for the quarter ended March 31, 2019.
(4)Dr. Coady owns 98,304 of these common units, which includes 20,000 unvested units that will vest on July 8, 2019. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole member. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 common units. Dr. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(5)Mr. Collingsworth owns 103,500 of these common units. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 2,250 of these common units. Cindy Collingsworth owns 870 of these common units
(6)Mr. Cropper owns 26,000 of these common units. The Donna L. Cropper Living Trust, of which Mr. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.
(7)Does not include 12,500 unvested units that will vest on November 13, 2019, 12,500 unvested units that will vest on February 11, 2020, 12,500 unvested units that will vest on November 10, 2020, 12,500 unvested units that will vest on February 11, 2021 and 12,500 unvested units that will vest on November 12, 2021.
(8)Units are held in The Suzanne and Jim Kneale Living Trust, of whom Mr. Kneale and his wife are trustees.
(9)Mr. Krimbill owns 831,417 of these common units, which includes 100,000 unvested units that will vest on July 8, 2019 and does not include 75,000 unvested units that will vest on February 11, 2020, 75,000 unvested units that will vest on November 10, 2020, 75,000 unvested units that will vest on February 11, 2021 and 75,000 unvested units that will vest on November 12, 2021. All of the unvested units noted above were reported on Mr. Krimbill’s Form 4. Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP also owns 283,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests and Krimbill Capital Group, LLC, which is owned 100% by the H. Michael Krimbill Revocable Trust, of which Mr. Krimbill is the trustee.
(10)Does not include 7,500 unvested units that will vest on November 13, 2019, 7,500 unvested units that will vest on February 11, 2020, 7,500 unvested units that will vest on November 10, 2020, 10,000 unvested units that will vest on February 11, 2021 and 10,000 unvested units that will vest on November 12, 2021.
(11)Mr. Osterman resigned from the board of directors effective January 22, 2019 and the information that follows is based on his last filed Form 4. Mr. Osterman owns 129,093 of these common units. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (122,016 common units), Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of these holding entities may be deemed to have sole voting and investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed to have sole voting and investment power over 798,393 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,185,337 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 1.65% interest in our general partner through VE Properties XI LLC.
(12)Mr. Raymond owns 50,000 of these common units. EMG NGL HC, LLC owns 176,634 of these common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGL HC LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.36% interest in our general partner.

(2)    The mailing address for Invesco Ltd. is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. Invesco Ltd. reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to Invesco Ltd. is based upon its Schedule 13G/A filed with the SEC on February 10, 2022.
(13)Does not include 5,000 unvested units that will vest on November 13, 2019, 5,000 unvested units that will vest on February 11, 2020, 5,000 unvested units that will vest on November 10, 2020, 5,000 unvested units that will vest on February 11, 2021 and 5,000 unvested units that will vest on November 12, 2021.
(14)The directors and executive officers of our general partner also collectively own a 58.58% interest in our general partner.
(3)    The mailing address for EIG Neptune Equity Aggregator, L.P. (“EIG Neptune”) is 600 New Hampshire Ave NW, Suite 1200, Washington, DC 20037. EIG Neptune reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to EIG Neptune is based upon its Schedule 13D/A filed with the SEC on September 4, 2020. The common units beneficially owned relate to warrants that were exercisable on July 2, 2020. For purposes of calculating ownership percentages, the units underlying the warrants are only deemed outstanding for purposes of calculating EIG Neptune’s percentage.
(4)    Does not include 75,000 unvested units, of which 25,000 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(5)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(6)    Dr. Coady owns 134,804 of these common units. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole member. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 of these common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 of these common units. Dr. Coady also owns a12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(7)    Mr. Collingsworth owns 340,000 of these common units. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 9,500 of these common units. Cindy Collingsworth owns 870 of these common units.
(8)Mr. Cropper owns 62,500 of these common units. The Donna L. Cropper Revocable Living Trust, of which Mr. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.
(9)    Mr. Krimbill owns 2,241,115 of these common units, which does not include 187,500 unvested units, of which 62,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. All of the unvested units noted above were reported on Mr. Krimbill’s Form 4. Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP also owns 488,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to
107


have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Krimbill Enterprises LP, II also owns 130,000 of these common units. Krimbill Enterprises LP, II is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests.
(10)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. Mr. McMurray owns a 0.25% interest in our general partner through MCM Investments, LLC, of which he owns 100% of the membership interests.
(11)    Does not include 41,250 unvested units, of which 13,750 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(12)    The directors and executive officers of our general partner also collectively own a 29.69% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2019.
2022.
Number of Securities to be

Issued upon Exercise of

Outstanding Options,

Warrants and Rights
Weighted-Average

Exercise Price of

Outstanding Options,

Warrants and Rights
Number of Securities

Remaining Available for

Future Issuances Under

Equity Compensation Plans

(Excluding Securities

Reflected in Column (a))
Plan Category (a)(b)(c)(1)
Equity Compensation Plans Approved by Security Holders


Equity Compensation Plans Not Approved by Security Holders (2)(1)2,308,4002,188,800 


Total2,308,4002,188,800 


(1)The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding common units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount.
(2)Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011. The adoption of the LTIP did not require the approval of our unitholders.

(1)    Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011, which did not require the approval of our unitholders. Prior to the expiration of the LTIP on May 10, 2021, we granted approximately 3.3 million common units as Service Awards, which will vest in our 2023 and 2024 fiscal years. Due to the LTIP expiring, we have no common units available for grant and any current unvested Service Awards that are forfeited or canceled will not be available for future grants.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 40,670,35744,208,446 common units, representing an aggregate 32.29%33.83% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distribution rights (“IDRs”). As of March 31, 2022, we owned 8.69% of our general partner.

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount of these expenses. In addition, our general partner owns the 0.1% general partner interest and all of the IDRs. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

The following table summarizes the distributions and payments to be made by us to our directors, executive officers, and greater than 5% ownersunitholders and our general partner in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.


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Operation Stage
Operation Stage
Distributions of available cash to our directors, executive officers, and greater than 5% ownersunitholders and our general partnerWe generally make cash distributions 99.9% to our unitholders pro rata, including our directors, executive officers, and greater than 5% ownersunitholders as the holders of an aggregate 40,670,35744,208,446 common units, and 0.1% to our general partner. In addition, when distributions exceed the minimum quarterly distribution and other higher target distributiondistributions levels, our general partner is entitled to increasing percentages of the distributions, up to 48.1% of the distributions above the highest target distribution level.
Assuming we have sufficient available cash to pay the same quarterly distribution on all of our outstanding units for four quarters that we paid in May 2019 ($0.39 per unit), our general partner would receive an annual distribution of $0.2 million on its general partner interest and incentive distribution rights, and our directors, officers, and greater than 5% owners would receive an aggregate annual distribution of $72.6 million on their common units.
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
As described in Note 7 to our consolidated financial statements included in this Annual Report, the indenture to the 2026 Senior Secured Notes restricts us from paying 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. In addition, quarterly distributions on the preferred units must be fully paid for all preceding fiscal quarters before we are permitted to declare or pay any distributions on our common units.
Payments to our general partner and its affiliatesOur general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. As the sole purpose of the general partner is to act as our general partner, substantially all of the expenses of our general partner are incurred on our behalf and reimbursed by us or our subsidiaries. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partnerIf our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
LiquidationUpon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Transactions Withwith Related Persons

WPX

Bryan K. Guderian is a member of our board of directors and an executive officer of WPX. We purchase crude oil from and sell crude oil to WPX (certain of the purchases and sales that were entered into in contemplation of each other are recorded on a net basis within revenues in our consolidated statement of operations). We also treat and dispose of wastewater and solids received from WPX. The following table summarizes transactions with WPX for the year ended March 31, 2019 (in thousands):
Sales to WPX$28,026
Purchases from WPX$329,525

During the three months ended June 30, 2018, we entered into a definitive agreement with WPX. Under this agreement, we agreed to provide WPX the benefit of our minimum shipping fees or deficiency credits (fees paid in previous periods that were in excess of the volumes actually shipped) totaling $67.7 million at the time of the transaction (as discussed further in Note 2 to our consolidated financial statements included in this Annual Report), which can be utilized for volumes shipped that exceed the minimum monthly volume commitment in subsequent periods. We also agreed that we would only ship crude oil that we are required to purchase from WPX in utilizing our allotted capacity on these pipelines and they agreed to be fully responsible to us for all deficiency payments (money due when our actual shipments are less than our allotted capacity)

for the remaining term of our contract, which totaled $50.3 million at June 30, 2018 (as discussed further in Note 9 to our consolidated financial statements included in this Annual Report). As consideration for this transaction, we paid WPX a net $35.3 million.

SemGroup

SemGroup holds an 11.78% ownership interest in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales, respectively, in our consolidated statements of operations (certain of the purchases and sales that were entered into in contemplation of each other are recorded on a net basis within revenues in our consolidated statement of operations). We also lease crude oil storage from SemGroup. The following table summarizes transactions with SemGroup for the year ended March 31, 2019 (in thousands):
Sales to SemGroup$11,764
Purchases from SemGroup$15,045

DCC

Shawn W. Coady is a member of our board of directors and an executive officer of DCC. We sell propane to and purchase propane from DCC. We also lease trucks from DCC. The following table summarizes transactions with DCC for the year ended March 31, 2019 (in thousands):
Sales to DCC$14,676
Purchases from DCC$289

Other Transactions

We purchase goods and services from certain entities that are partially owned by our named executive officers and former named executive officer (Vincent J. Osterman).officers. The following table summarizes these transactions from April 1, 2021 to March 31, 2022:
EntityNature of PurchasesAmount PurchasedOwnership Interest in Entity
(in thousands)
H. Michael Krimbill
KAIR2014 LLC (“KAIR2014”)Aircraft$670 50 %

In connection with the purchase of our 50% interest in an aircraft company, KAIR2014, we executed a joint and several guarantee for the year endedbenefit of the lender for KAIR2014’s outstanding loan. The other owner of KAIR2014, our Chief Executive Officer, H. Michael Krimbill, 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 March 31, 2019:
Entity Nature of Purchases 
Amount
Purchased
 
Ownership Interest
in Entity
    (in thousands)  
Vincent J. Osterman      
VE Properties III, LLC Office space rental $36
 100%
H. Michael Krimbill      
Pinnacle Aviation 2007, LLC Aircraft rental $216
 50%
H. Michael Krimbill      
KAIR2014 LLC Aircraft rental $211
 50%

Timothy Osterman, a former employee2022, the outstanding balance of the Partnership,loan is approximately $2.5 million. Payments are made monthly, reducing the son of Vincent J. Osterman, whooutstanding balance, and the loan matures in September 2023. As the guarantee is a former executive officerjoint and several, we could be liable for the entire outstanding balance of the Partnershiploan. The loan is collateralized by the airplane owned by KAIR2014 and in the event of a former memberdefault, the lender could seek payment in full from us. As of the board of directors and was an employee of the Partnership. Timothy Osterman resigned from the Partnership on July 10, 2018. Timothy Osterman received total compensation of approximately $0.4 million during the year ended March 31, 2019.2022, no accrual has been recorded related to this guarantee.
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Travis Krimbill, an employee of the Partnership, is the son of H. Michael Krimbill, who is a named executive officer of the Partnership and a member of the board of directors. Travis Krimbill does not report to H. Michael Krimbill and his compensation is determined by the Chief Financial Officer. During the year ended March 31, 2019,2022, Travis Krimbill received total compensation of approximately $0.1$0.2 million.

Registration Rights Agreement

We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registration rights parties”) pursuant to which we agreed to register for resale under the Securities Act of 1933, as amended (“Securities Act”) common units owned by the parties to the Registration Rights Agreement. In connection with our IPO, we granted registration rights to the NGL Energy LPGP Investor Group, and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if an

exemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject to limitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following:

Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that they continue to own more than 4% of our common units, require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file a total of nine registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million.
Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.
Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

 Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that they continue to own more than 4% of our common units, require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file a total of nine registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million.
Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.
Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies for the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers will make all reasonable efforts to cancel or annul the transaction.

The Code of Business Conduct and Ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to:

whether there is an appropriate business justification for the transaction;
the benefits that accrue to the Partnership as a result of the transaction;
the terms available to unrelated third parties entering into similar transactions;
the impact of the transaction on a director’s independence (in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer);
the availability of other sources for comparable products or services;
110


whether it is a single transaction or a series of ongoing, related transactions; and
whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

Director Independence

The NYSE does not require a listed publicly traded limited partnership like usNGL to have a majority of independent directors on the board of directors of ourits general partner. For a discussion of the independence of the board of directors of our general partner, see Part III, Item 10–“Directors, Executive Officers and Corporate GovernanceGovernance–Board of Directors of our General PartnerPartner.”
.”


Item 14.    Principal AccountingAccountant Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Grant Thornton LLP to audit our annual consolidated financial statements and for other services for the periods indicated:
  March 31,
  2019 2018
Audit fees (1) $2,500,800
 $2,507,000
Audit-related fees (2) 120,000
 
Tax fees 
 
All other fees 3,500
 
Total $2,624,300
 $2,507,000
March 31,
20222021
(in thousands)
Audit fees (1)$1,882 $2,149 
Audit-related fees (2)— 
Tax fees— — 
All other fees— — 
Total$1,882 $2,156 
(1)Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.
(2)Includes audits of financial statements for businesses divested during the fiscal year.
(1)    Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.
(2)    Includes fees in fiscal year 2021 for review services for one of our subsidiaries.

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.


111


PART IV
Item 15.    Exhibits,Exhibit and Financial Statement Schedules


(a)    The following documents are filed as part of this Annual Report:
1.    Financial Statements. See the accompanying Index to Financial Statements.
2.    Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.
3.    Exhibits.
(a)The following documents are filed as part of this Annual Report:
1.
Financial Statements. See the accompanying Index to Financial Statements.
2.
Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.
3.Exhibits.
Exhibit NumberDescription
2.1
2.2
2.3
2.4
2.5
2.6
2.7
3.12.2
2.3
2.4
2.5
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.103.11
3.12
3.13
3.14

112


Exhibit NumberDescription
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
113


Exhibit NumberDescription
4.20
4.21
4.22*
4.23
4.194.24

4.25
Exhibit NumberDescription
4.20
4.214.26
4.224.27
4.234.28
4.29
4.30
4.31
4.32*
4.33
4.244.34
4.254.35
4.264.36
4.37
4.38
114


Exhibit NumberDescription
4.39
4.40*
4.41
4.42
4.43*
4.44
10.14.45
4.46
4.47*
10.1
10.2
10.3
10.4
10.510.3*
10.4*
10.610.5
10.7
10.8
10.9
10.10+10.6+
10.11+10.7+
21.1*10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
115



22.1*
Exhibit Number23.1*Description
23.1*
31.1*
31.2*
32.1*
32.2*
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
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*
*    Exhibits filed with this report.
**The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2019 and 2018, (ii) Consolidated Statements of Operations for the years ended March 31, 2019, 2018, and 2017, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2019, 2018, and 2017, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2019, 2018, and 2017, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2019, 2018, and 2017, and (vi) Notes to Consolidated Financial Statements.
+Management contracts or compensatory plans or arrangements.

**    The following documents are formatted in Inline XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2022 and 2021, (ii) Consolidated Statements of Operations for the years ended March 31, 2022, 2021, and 2020, (iii) Consolidated Statements of Comprehensive Loss for the years ended March 31, 2022, 2021, and 2020, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2022, 2021, and 2020, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2022, 2021, and 2020, and (vi) Notes to Consolidated Financial Statements.
+    Management contracts or compensatory plans or arrangements.

Item 16.    Form 10-K Summary

None.

116



SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 30, 2019.
June 6, 2022.
NGL ENERGY PARTNERS LP
By:NGL Energy Holdings LLC, its general partner
By:/s/ H. Michael Krimbill
H. Michael Krimbill
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ H. Michael KrimbillChief Executive Officer and DirectorJune 6, 2022
H. Michael Krimbill(Principal Executive Officer)
SignatureTitleDate
/s/ H. Michael KrimbillLinda J. BridgesChief Executive Officer and DirectorMay 30, 2019
H. Michael Krimbill(Principal Executive Officer)
/s/ Robert W. Karlovich IIIChief Financial OfficerMay 30, 2019June 6, 2022
Robert W. Karlovich IIILinda J. Bridges(Principal Financial Officer)
/s/ Lawrence J. ThuillierChief Accounting OfficerMay 30, 2019June 6, 2022
Lawrence J. Thuillier(Principal Accounting Officer)
/s/ Shawn W. CoadyDirectorMay 30, 2019June 6, 2022
Shawn W. Coady
/s/ James M. CollingsworthDirectorMay 30, 2019June 6, 2022
James M. Collingsworth
/s/ Stephen L. CropperDirectorMay 30, 2019June 6, 2022
Stephen L. Cropper
/s/ Bryan K. GuderianDirectorMay 30, 2019June 6, 2022
Bryan K. Guderian
/s/ James C. KnealeDirectorMay 30, 2019
James C. Kneale
/s/ John T. RaymondDirectorMay 30, 2019June 6, 2022
John T. Raymond
/s/ L. John Schaufele IVDerek S. ReinersDirectorMay 30, 2019June 6, 2022
L. John Schaufele IVDerek S. Reiners
/s/ Randall S. WadeDirectorJune 6, 2022
Randall S. Wade

117


INDEX TO FINANCIAL STATEMENTS
 
NGL Energy Partners LP
NGL ENERGY PARTNERS LP
ReportsReport of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
F-2
Consolidated Balance Sheets at March 31, 20192022 and 20182021
F-4
Consolidated Statements of Operations for the years ended March 31, 2019, 2018,2022, 2021, and 20172020
F-5
Consolidated Statements of Comprehensive Income (Loss)Loss for the years ended March 31, 2019, 2018,2022, 2021, and 20172020
F-6
Consolidated Statements of Changes in Equity for the years ended March 31, 2019, 2018,2022, 2021, and 20172020
F-7
Consolidated Statements of Cash Flows for the years ended March 31, 2019, 2018,2022, 2021, and 20172020
F-8
Notes to Consolidated Financial Statements
F-109


F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

PartnersBoard of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 20192022 and 2018,2021, the related consolidated statements of operations, comprehensive income (loss),loss, changes in equity, and cash flows for each of the three years in the period ended March 31, 2019,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of March 31, 20192022 and 2018,2021, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2019,2022, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of March 31, 2019,2022, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated May 30, 2019June 6, 2022 expressed an unqualified opinion.

Basis for opinionopinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


Critical audit matter
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2010.
Tulsa, Oklahoma
May 30, 2019


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners
NGL Energy Partners LP

OpinionThe critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on internal control overthe financial reportingstatements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
We have audited
Goodwill Impairment Assessment
As described further in Note 5 to the internal control overconsolidated financial reporting of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”)statements, the Partnership’s consolidated goodwill balance was $744.4 million as of March 31, 2019, based2022. Management evaluates goodwill for impairment on criteria established inJanuary 1 of each year, or more frequently to the 2013 Internal Control-Integrated Framework issued byextent events or conditions indicate a risk of possible impairment. Management performed a quantitative impairment assessment for the CommitteeCrude Oil Logistics reporting unit to test goodwill for impairment as of Sponsoring OrganizationsJanuary 1, 2022. As a result of the Treadway Commission (“COSO”). In our opinion,assessment performed for the Partnership maintained,reporting unit, and as described further in all material respects, effective internal control over financial reporting as of March 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”),Note 5 to the consolidated financial statements, the Partnership concluded the fair value of the PartnershipCrude Oil Logistics reporting unit exceeded its carrying value and no goodwill impairment was recorded. We identified the goodwill impairment assessment as of and for the year ended March 31, 2019, and our report dated May 30, 2019 expressed an unqualified opinionon those financial statements.a critical audit matter.
Basis for opinion
The Partnership’s management is responsibleprincipal considerations for maintaining effective internal control over financial reportingour determination that the goodwill impairment assessment was a critical audit matter are that there was a high estimation uncertainty due to significant judgments with respect to assumptions used to estimate the future revenues and for itscash flows, including revenue growth rates, operating expenses and cash outflows necessary to support the cash flows, weighted average costs of capital and future market conditions as well as the valuation methodologies applied by the Partnership. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to management’s forecasted future revenues and cash flows. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
F-2



Our audit procedures related to the goodwill impairment assessment ofincluded the following, among others. We tested the effectiveness of internal controlcontrols relating to management’s goodwill impairment tests, including controls over financialthe determination of the fair value of the reporting includedunit. In addition to testing the effectiveness of controls, we also performed the following:

Utilized a valuation specialist to evaluate:
The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing an independent calculation,
The appropriateness of the discount rate by recalculating the weighted average costs of capital and evaluating future market conditions, and
Other significant assumptions, including the terminal growth rate.
Tested the reasonableness of management’s process for determining the fair value of the reporting unit, including the revenue growth rate, forecasted costs and operating margins by comparing such items to the industry projections and conditions found in industry reports as well as historical operating results of the reporting unit and by assessing the likelihood or capability of the reporting unit to undertake activities or initiatives underpinning significant drivers of growth in the accompanying Management’s Report on Internal Control Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion onforecasted period.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.auditor since 2010.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reportingTulsa, Oklahoma
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.June 6, 2022
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-3
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
May 30, 2019



NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Balance Sheets
(in Thousands, except unit amounts)
 March 31,
 2019 2018
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$18,572
 $22,094
Accounts receivable-trade, net of allowance for doubtful accounts of $4,366 and $4,201, respectively1,162,919
 1,026,764
Accounts receivable-affiliates12,867
 4,772
Inventories463,143
 551,303
Prepaid expenses and other current assets155,172
 128,742
Assets held for sale
 517,604
Total current assets1,812,673
 2,251,279
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $420,362 and $343,345, respectively1,844,493
 1,518,607
GOODWILL1,145,861
 1,204,607
INTANGIBLE ASSETS, net of accumulated amortization of $524,257 and $433,565, respectively938,335
 913,154
INVESTMENTS IN UNCONSOLIDATED ENTITIES1,127
 17,236
LOAN RECEIVABLE-AFFILIATE
 1,200
OTHER NONCURRENT ASSETS160,004
 245,039
Total assets$5,902,493
 $6,151,122
LIABILITIES AND EQUITY   
CURRENT LIABILITIES AND REDEEMABLE NONCONTROLLING INTEREST:   
Accounts payable-trade$964,665
 $852,839
Accounts payable-affiliates28,469
 1,254
Accrued expenses and other payables248,450
 223,504
Advance payments received from customers8,921
 8,374
Current maturities of long-term debt648
 646
Liabilities and redeemable noncontrolling interest held for sale
 42,580
Total current liabilities and redeemable noncontrolling interest1,251,153
 1,129,197
LONG-TERM DEBT, net of debt issuance costs of $12,008 and $20,645, respectively, and current maturities2,160,133
 2,679,740
OTHER NONCURRENT LIABILITIES63,575
 173,514
COMMITMENTS AND CONTINGENCIES (NOTE 9)


 


    
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 19,942,169 preferred units issued and outstanding, respectively149,814
 82,576
    
EQUITY:   
General partner, representing a 0.1% interest, 124,633 and 121,594 notional units, respectively(50,603) (50,819)
Limited partners, representing a 99.9% interest, 124,508,497 and 121,472,725 common units issued and outstanding, respectively2,067,197
 1,852,495
Class B preferred limited partners, 8,400,000 and 8,400,000 preferred units issued and outstanding, respectively202,731
 202,731
Accumulated other comprehensive loss(255) (1,815)
Noncontrolling interests58,748
 83,503
Total equity2,277,818
 2,086,095
Total liabilities and equity$5,902,493
 $6,151,122

March 31,
20222021
ASSETS
CURRENT ASSETS:
Cash and cash equivalents$3,822 $4,829 
Accounts receivable-trade, net of allowance for expected credit losses of $2,626 and $2,192, respectively1,123,163 725,943 
Accounts receivable-affiliates8,591 9,435 
Inventories251,277 158,467 
Prepaid expenses and other current assets159,486 109,164 
Total current assets1,546,339 1,007,838 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $887,006 and $776,279, respectively2,462,390 2,706,853 
GOODWILL744,439 744,439 
INTANGIBLE ASSETS, net of accumulated amortization of $507,285 and $517,518, respectively1,135,354 1,262,613 
INVESTMENTS IN UNCONSOLIDATED ENTITIES21,897 22,719 
OPERATING LEASE RIGHT-OF-USE ASSETS114,124 152,146 
OTHER NONCURRENT ASSETS45,802 50,733 
Total assets$6,070,345 $5,947,341 
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade$1,084,837 $679,868 
Accounts payable-affiliates73 119 
Accrued expenses and other payables140,719 170,400 
Advance payments received from customers7,934 11,163 
Current maturities of long-term debt2,378 2,183 
Operating lease obligations41,261 47,070 
Total current liabilities1,277,202 910,803 
LONG-TERM DEBT, net of debt issuance costs of $42,988 and $55,555, respectively, and current maturities3,350,463 3,319,030 
OPERATING LEASE OBLIGATIONS72,784 103,637 
OTHER NONCURRENT LIABILITIES104,346 114,615 
COMMITMENTS AND CONTINGENCIES (NOTE 8)00
CLASS D 9.00% PREFERRED UNITS, 600,000 and 600,000 preferred units issued and outstanding, respectively551,097 551,097 
EQUITY:
General partner, representing a 0.1% interest, 130,827 and 129,724 notional units, respectively(52,478)(52,189)
Limited partners, representing a 99.9% interest, 130,695,970 and 129,593,939 common units issued and outstanding, respectively401,486 582,784 
Class B preferred limited partners, 12,585,642 and 12,585,642 preferred units issued and outstanding, respectively305,468 305,468 
Class C preferred limited partners, 1,800,000 and 1,800,000 preferred units issued and outstanding, respectively42,891 42,891 
Accumulated other comprehensive loss(308)(266)
Noncontrolling interests17,394 69,471 
Total equity714,453 948,159 
Total liabilities and equity$6,070,345 $5,947,341 
The accompanying notes are an integral part of these consolidated financial statements.

F-4


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Operations
(in Thousands, except unit and per unit amounts)
 Year Ended March 31,
 2019 2018 2017
REVENUES:     
Crude Oil Logistics$3,136,635
 $2,260,075
 $1,666,884
Water Solutions301,686
 229,139
 159,601
Liquids2,415,041
 2,215,985
 1,537,172
Refined Products and Renewables18,162,183
 12,200,923
 9,342,702
Other1,362
 1,174
 844
Total Revenues24,016,907
 16,907,296
 12,707,203
COST OF SALES:     
Crude Oil Logistics2,902,656
 2,113,747
 1,572,015
Water Solutions(10,787) 19,345
 4,068
Liquids2,277,709
 2,128,522
 1,432,200
Refined Products and Renewables18,113,410
 12,150,497
 9,219,721
Other1,929
 530
 400
Total Cost of Sales23,284,917
 16,412,641
 12,228,404
OPERATING COSTS AND EXPENSES:     
Operating240,684
 201,068
 189,003
General and administrative107,534
 98,129
 105,805
Depreciation and amortization212,860
 209,020
 180,239
Loss (gain) on disposal or impairment of assets, net34,296
 (17,104) (208,890)
Revaluation of liabilities(5,373) 20,716
 6,717
Operating Income (Loss)141,989
 (17,174) 205,925
OTHER INCOME (EXPENSE):     
Equity in earnings of unconsolidated entities2,533
 7,539
 3,830
Revaluation of investments
 
 (14,365)
Interest expense(164,726) (199,148) (149,994)
(Loss) gain on early extinguishment of liabilities, net(12,340) (23,201) 24,727
Other (expense) income, net(29,946) 6,953
 26,612
(Loss) Income From Continuing Operations Before Income Taxes(62,490) (225,031) 96,735
INCOME TAX EXPENSE(1,234) (1,354) (1,933)
(Loss) Income From Continuing Operations(63,724) (226,385) 94,802
Income From Discontinued Operations, net of Tax403,119
 156,780
 49,072
Net Income (Loss)339,395
 (69,605) 143,874
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS20,206
 (240) (6,832)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS446
 (1,030) 
NET INCOME (LOSS) ATTRIBUTABLE TO NGL ENERGY PARTNERS LP$360,047
 $(70,875) $137,042
      
NET (LOSS) INCOME FROM CONTINUING OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(155,437) $(286,521) $57,645
NET INCOME FROM DISCONTINUED OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$403,161
 $155,595
 $49,023
NET INCOME (LOSS) ALLOCATED TO COMMON UNITHOLDERS$247,724
 $(130,926) $106,668
BASIC INCOME (LOSS) PER COMMON UNIT     
(Loss) Income From Continuing Operations$(1.26) $(2.37) $0.53
Income From Discontinued Operations, net of Tax$3.28
 $1.29
 $0.45
Net Income (Loss)$2.01
 $(1.08) $0.99
DILUTED INCOME (LOSS) PER COMMON UNIT     
(Loss) Income From Continuing Operations$(1.26) $(2.37) $0.52
Income From Discontinued Operations, net of Tax$3.28
 $1.29
 $0.44
Net Income (Loss)$2.01
 $(1.08) $0.95
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING123,017,064
 120,991,340
 108,091,486
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING123,017,064
 120,991,340
 111,850,621
Year Ended March 31,
202220212020
REVENUES:
Water Solutions$544,866 $370,986 $422,059 
Crude Oil Logistics2,505,496 1,721,636 2,549,767 
Liquids Logistics4,897,553 3,133,146 4,611,136 
Corporate and Other— 1,255 1,038 
Total Revenues7,947,915 5,227,023 7,584,000 
COST OF SALES:
Water Solutions33,980 9,622 (33,870)
Crude Oil Logistics2,352,932 1,515,993 2,293,953 
Liquids Logistics4,752,400 2,966,391 4,342,526 
Corporate and Other— 1,816 1,774 
Total Cost of Sales7,139,312 4,493,822 6,604,383 
OPERATING COSTS AND EXPENSES:
Operating285,535 254,562 332,993 
General and administrative63,546 70,468 113,664 
Depreciation and amortization288,720 317,227 265,312 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Revaluation of liabilities(6,495)6,261 9,194 
Operating Income (Loss)83,043 (390,753)(3,332)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities1,400 1,938 1,291 
Interest expense(271,640)(198,799)(181,184)
Gain (loss) on early extinguishment of liabilities, net1,813 (16,692)1,341 
Other income (expense), net2,254 (36,503)1,684 
Loss From Continuing Operations Before Income Taxes(183,130)(640,809)(180,200)
INCOME TAX (EXPENSE) BENEFIT(971)3,391 (345)
Loss From Continuing Operations(184,101)(637,418)(180,545)
Loss From Discontinued Operations, net of Tax— (1,769)(218,235)
Net Loss(184,101)(639,187)(398,780)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS(655)(632)1,773 
NET LOSS ATTRIBUTABLE TO NGL ENERGY PARTNERS LP$(184,756)$(639,819)$(397,007)
NET LOSS FROM CONTINUING OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(730,683)$(367,246)
NET LOSS FROM DISCONTINUED OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$— $(1,767)$(218,017)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(732,450)$(585,263)
BASIC LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
DILUTED LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
 The accompanying notes are an integral part of these consolidated financial statements.

F-5


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)Loss
(in Thousands)

Year Ended March 31,
202220212020
Net loss$(184,101)$(639,187)$(398,780)
Other comprehensive (loss) income(42)119 (130)
Comprehensive loss$(184,143)$(639,068)$(398,910)
 Year Ended March 31,
 2019 2018 2017
Net income (loss)$339,395
 $(69,605) $143,874
Other comprehensive (loss) income(9) 13
 (1,671)
Comprehensive income (loss)$339,386
 $(69,592) $142,203

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


F-6


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended March 31, 2019, 2018,2022, 2021, and 20172020
(in Thousands, except unit amounts)
   Limited Partners      
   Class B Preferred Common      
 
General
Partner
 Units Amount 

Units
 Amount Accumulated Other Comprehensive Income (Loss) 
Noncontrolling
Interests
 
Total
Equity
BALANCES AT MARCH 31, 2016$(50,811) 
 $
 104,169,573
 $1,707,326
 $(157) $37,707
 $1,694,065
Distributions to general and common unit partners and preferred unitholders (Note 10)(287) 
 
 
 (181,294) 
 
 (181,581)
Distributions to noncontrolling interest owners
 
 
 
 
 
 (3,292) (3,292)
Contributions49
 
 
 
 (501) 
 1,173
 721
Business combinations
 
 
 218,617
 3,940
 
 
 3,940
Purchase of noncontrolling interest
 
 
 
 (215) 
 (12,602) (12,817)
Equity issued pursuant to incentive compensation plan (Note 10)
 
 
 2,350,082
 68,414
 
 
 68,414
Common units issued, net of offering costs (Note 10)288
 
 
 13,441,135
 286,848
 
 
 287,136
Allocation of value to beneficial conversion feature of Class A convertible preferred units (Note 10)
 
 
 
 131,534
 
 
 131,534
Issuance of warrants, net of offering costs (Note 10)
 
 
 
 48,550
 
 
 48,550
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)
 
 
 
 (8,999) 
 
 (8,999)
Transfer of redeemable noncontrolling interest (Note 2)
 
 
 
 
 
 (3,072) (3,072)
Net income232
 
 
 
 136,810
 
 6,832
 143,874
Other comprehensive loss
 
 
 
 
 (1,671) 
 (1,671)
BALANCES AT MARCH 31, 2017(50,529) 
 
 120,179,407
 2,192,413
 (1,828) 26,746
 2,166,802
Distributions to general and common unit partners and preferred unitholders (Note 10)(323) 
 
 
 (229,469) 
 
 (229,792)
Distributions to noncontrolling interest owners
 
 
 
 
 
 (3,082) (3,082)
Contributions
 
 
 
 
 
 23
 23
Sawtooth joint venture (Note 16)
 
 
 
 (16,981) 
 76,214
 59,233
Purchase of noncontrolling interest (Note 4)
 
 
 
 (6,245) 
 (16,638) (22,883)
Redeemable noncontrolling interest valuation adjustment (Note 2)
 
 
 
 (5,825) 
 
 (5,825)
Repurchase of warrants (Note 10)
 
 
 
 (10,549) 
 
 (10,549)
Equity issued pursuant to incentive compensation plan (Note 10)28
 
 
 2,260,011
 34,623
 
 
 34,651
Common unit repurchases and cancellations (Note 10)
 
 
 (1,574,346) (15,817) 
 
 (15,817)
Warrants exercised (Note 10)
 
 
 607,653
 6
 
 
 6
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)
 
 
 
 (18,781) 
 
 (18,781)
Issuance of Class B preferred units, net of offering costs (Note 10)
 8,400,000
 202,731
 
 
 
 
 202,731
Net income (loss)5
 
 
 
 (70,880) 
 240
 (70,635)
Other comprehensive income
 
 
 
 
 13
 
 13
BALANCES AT MARCH 31, 2018(50,819) 8,400,000
 202,731
 121,472,725
 1,852,495
 (1,815) 83,503
 2,086,095
Distributions to general and common unit partners and preferred unitholders (Note 10)(330) 
 
 
 (236,303) 
 
 (236,633)
Contributions
 
 
 
 
 
 169
 169
Sawtooth joint venture (Note 16)
 
 
 
 (63) 
 (791) (854)
Purchase of noncontrolling interest (Note 4)
 
 
 
 (33) 
 (3,927) (3,960)
Redeemable noncontrolling interest valuation adjustment (Note 2)
 
 
 
 (3,349) 
 
 (3,349)
Repurchase of warrants (Note 10)
 
 
 
 (14,988) 
 
 (14,988)
Common unit repurchases and cancellations (Note 10)
 
 
 (26,993) (297) 
 
 (297)
Equity issued pursuant to incentive compensation plan (Note 10)22
 
 
 2,833,968
 39,712
 
 
 39,734
Warrants exercised (Note 10)
 
 
 228,797
 2
 
 
 2
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)
 
 
 
 (67,239) 
 
 (67,239)
Net income (loss)387
 
 
 
 359,660
 
 (20,206) 339,841
Other comprehensive loss
 
 
 
 
 (9) 
 (9)
Cumulative effect adjustment for adoption of ASC 606 (Note 15)139
 
 
 
 139,167
 
 
 139,306
Cumulative effect adjustment for adoption of ASU 2016-01 (Note 2)(2) 
 
 
 (1,567) 1,569
 
 
BALANCES AT MARCH 31, 2019$(50,603) 8,400,000
 $202,731
 124,508,497
 $2,067,197
 $(255) $58,748
 $2,277,818
Limited Partners
PreferredCommon
General
Partner
UnitsAmount
Units
AmountAccumulated Other Comprehensive Income (Loss)Noncontrolling
Interests
Total
Equity
BALANCES AT MARCH 31, 2019$(50,603)8,400,000 $202,731 124,508,497 $2,067,197 $(255)$58,748 $2,277,818 
Distributions to general and common unit partners and preferred unitholders (Note 9)(342)— — — (258,020)— — (258,362)
Distributions to noncontrolling interest owners— — — — — — (1,145)(1,145)
Issuance of Class B preferred units, net of offering costs (Note 9)— 4,185,642 102,737 — — — — 102,737 
Issuance of Class C preferred units, net of offering costs (Note 9)— 1,800,000 42,891 — — — — 42,891 
Issuance of warrants, net of offering costs (Note 9)— — — — 52,742 — — 52,742 
Warrants exercised (Note 9)— — — 1,458,371 15 — — 15 
Accretion of beneficial conversion feature of 10.75% Class A convertible preferred units (Note 9)— — — — (36,517)— — (36,517)
10.75% Class A convertible preferred units redemption - amount paid in excess of carrying value (Note 9)— — — — (78,797)— — (78,797)
Equity issued pursuant to incentive compensation plan33 — — 2,938,481 32,931 — — 32,964 
Common unit repurchases and cancellations— — — (133,634)(1,644)— — (1,644)
Mesquite Disposals Unlimited, LLC ("Mesquite") acquisition— — — — — — 17,124 17,124 
Investment in NGL Energy Holdings LLC (Note 12)— — — — (15,226)— — (15,226)
Net loss(478)— — — (396,529)— (1,773)(398,780)
Other comprehensive loss— — — — — (130)— (130)
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 (Note 9)(65)— — — (147,715)— — (147,780)
Distributions to noncontrolling interest owners— — — — — — (4,115)(4,115)
Common unit repurchases and cancellations— — — (70,226)(182)— — (182)
Equity issued pursuant to incentive compensation plan— — — 892,450 4,727 — — 4,727 
Net (loss) income(733)— — — (639,086)— 632 (639,187)
Other comprehensive income— — — — — 119 — 119 
Cumulative effect adjustment for adoption of ASU 2016-13 (Note 16)(1)— — — (1,112)— — (1,113)
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— — — — — — (1,635)(1,635)
Sawtooth joint venture disposition (Note 17)— — — — — — (51,097)(51,097)
Common unit repurchases and cancellations (Note 9)— — — (44,769)(90)— — (90)
Equity issued pursuant to incentive compensation plan (Note 9)— — — 1,146,800 3,259 — — 3,259 
Net (loss) income(289)— — — (184,467)— 655 (184,101)
Other comprehensive loss— — — — — (42)— (42)
BALANCES AT MARCH 31, 2022$(52,478)14,385,642 $348,359 130,695,970 $401,486 $(308)$17,394 $714,453 
The accompanying notes are an integral part of these consolidated financial statements.

F-7


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in Thousands)
 Year Ended March 31,
 2019 2018 2017
OPERATING ACTIVITIES:     
Net income (loss)$339,395
 $(69,605) $143,874
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:     
Income from discontinued operations, net of tax(403,119) (156,780) (49,072)
Depreciation and amortization, including amortization of debt issuance costs227,694
 225,738
 194,829
Loss (gain) on early extinguishment or revaluation of liabilities, net6,967
 43,917
 (18,010)
Gain on termination of a storage sublease agreement
 
 (16,205)
Non-cash equity-based compensation expense41,367
 35,241
 53,102
Loss (gain) on disposal or impairment of assets, net34,296
 (17,104) (208,890)
Provision for doubtful accounts369
 590
 (1,000)
Net adjustments to fair value of commodity derivatives(33,631) 116,604
 55,978
Equity in earnings of unconsolidated entities(2,533) (7,539) (3,830)
Distributions of earnings from unconsolidated entities2,206
 4,632
 3,564
Lower of cost or market value adjustment50,987
 399
 (1,283)
Revaluation of investments
 
 14,365
Other(485) (41) (7,809)
Changes in operating assets and liabilities, exclusive of acquisitions:     
Accounts receivable-trade and affiliates(144,209) (272,990) (254,124)
Inventories52,870
 (8,048) (189,311)
Other current and noncurrent assets44,261
 (22,472) (54,184)
Accounts payable-trade and affiliates101,699
 195,339
 236,633
Other current and noncurrent liabilities(10,620) (14,252) 3,573
Net cash provided by (used in) operating activities-continuing operations307,514
 53,629
 (97,800)
Net cash provided by operating activities-discontinued operations29,736
 84,338
 72,762
Net cash provided by (used in) operating activities337,250
 137,967
 (25,038)
INVESTING ACTIVITIES:     
Capital expenditures(455,613) (133,761) (344,936)
Acquisitions, net of cash acquired(316,936) (19,897) (41,928)
Net settlements of commodity derivatives18,405
 (100,405) (37,086)
Proceeds from sales of assets16,177
 33,844
 28,232
Proceeds from divestitures of businesses and investments, net335,809
 329,780
 134,370
Transaction with Victory Propane (Note 13)
 (6,424) 
Investments in unconsolidated entities(389) (21,465) (2,105)
Distributions of capital from unconsolidated entities1,440
 11,969
 9,692
Repayments on loan for natural gas liquids facility10,336
 10,052
 8,916
Loan to affiliate(1,515) (2,510) (3,200)
Repayments on loan to affiliate
 4,160
 655
Payment to terminate development agreement
 
 (16,875)
Net cash (used in) provided by investing activities-continuing operations(392,286) 105,343
 (264,265)
Net cash provided by (used in) investing activities-discontinued operations845,759
 165,239
 (98,861)
Net cash provided by (used in) investing activities453,473
 270,582
 (363,126)
FINANCING ACTIVITIES:     
Proceeds from borrowings under revolving credit facilities4,098,500
 2,434,500
 1,700,000
Payments on revolving credit facilities(3,897,000) (2,279,500) (2,733,500)
Issuance of senior unsecured notes
 
 1,200,000
Repayment and repurchase of senior secured and senior unsecured notes(737,058) (486,699) (21,193)
Payments on other long-term debt(653) (877) (46,153)
Debt issuance costs(1,383) (2,700) (33,558)
Contributions from general partner
 
 49
Contributions from noncontrolling interest owners, net169
 23
 672
Distributions to general and common unit partners and preferred unitholders(236,633) (225,067) (181,581)
Distributions to noncontrolling interest owners
 (3,082) (3,292)
Proceeds from sale of preferred units, net of offering costs
 202,731
 234,975
Repurchase of warrants(14,988) (10,549) 
Common unit repurchases and cancellations(297) (15,817) 
Proceeds from sale of common units, net of offering costs
 
 287,136
Payments for settlement and early extinguishment of liabilities(4,577) (3,408) (28,468)
Net cash (used in) provided by financing activities-continuing operations(793,920) (390,445) 375,087
Net cash used in financing activities-discontinued operations(325) (3,836) (3,633)
Net cash (used in) provided by financing activities(794,245) (394,281) 371,454
Net (decrease) increase in cash and cash equivalents(3,522) 14,268
 (16,710)
Cash and cash equivalents, beginning of period22,094
 7,826
 24,536
Cash and cash equivalents, end of period$18,572
 $22,094
 $7,826

Year Ended March 31,
202220212020
OPERATING ACTIVITIES:OPERATING ACTIVITIES:
Net lossNet loss$(184,101)$(639,187)$(398,780)
Adjustments to reconcile net loss to net cash provided by operating activities:Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations, net of taxLoss from discontinued operations, net of tax— 1,769 218,235 
Depreciation and amortization, including amortization of debt issuance costsDepreciation and amortization, including amortization of debt issuance costs306,208 331,200 276,848 
(Gain) loss on early extinguishment or revaluation of liabilities, net(Gain) loss on early extinguishment or revaluation of liabilities, net(8,308)22,953 7,853 
Non-cash equity-based compensation expenseNon-cash equity-based compensation expense(1,052)6,727 26,510 
Loss on disposal or impairment of assets, netLoss on disposal or impairment of assets, net94,254 475,436 261,786 
Change in provision for expected credit lossesChange in provision for expected credit losses929 5,988 1,002 
Net adjustments to fair value of commodity derivativesNet adjustments to fair value of commodity derivatives116,556 83,578 (85,941)
Equity in earnings of unconsolidated entitiesEquity in earnings of unconsolidated entities(1,400)(1,938)(1,291)
Distributions of earnings from unconsolidated entitiesDistributions of earnings from unconsolidated entities2,205 3,364 — 
Lower of cost or net realizable value adjustmentsLower of cost or net realizable value adjustments14,761 3,898 33,973 
OtherOther2,310 1,513 2,541 
Changes in operating assets and liabilities, exclusive of acquisitions:Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliatesAccounts receivable-trade and affiliates(397,607)(162,031)436,349 
InventoriesInventories(119,806)(92,731)29,779 
Other current and noncurrent assetsOther current and noncurrent assets40,158 92,555 14,081 
Accounts payable-trade and affiliatesAccounts payable-trade and affiliates405,420 207,505 (375,257)
Other current and noncurrent liabilitiesOther current and noncurrent liabilities(64,681)(34,836)(65,262)
Net cash provided by operating activities-continuing operationsNet cash provided by operating activities-continuing operations205,846 305,763 382,426 
Net cash (used in) provided by operating activities-discontinued operationsNet cash (used in) provided by operating activities-discontinued operations— (1,769)81,629 
Net cash provided by operating activitiesNet cash provided by operating activities205,846 303,994 464,055 
INVESTING ACTIVITIES:INVESTING ACTIVITIES:
Capital expendituresCapital expenditures(142,359)(186,801)(555,713)
Acquisitions, net of cash acquiredAcquisitions, net of cash acquired— 901 (1,268,474)
Net settlements of commodity derivativesNet settlements of commodity derivatives(152,055)(80,372)86,702 
Proceeds from sales of assetsProceeds from sales of assets18,500 45,742 17,621 
Proceeds from divestitures of businesses and investments, netProceeds from divestitures of businesses and investments, net63,489 — — 
Investments in unconsolidated entitiesInvestments in unconsolidated entities(350)(963)(21,218)
Distributions of capital from unconsolidated entitiesDistributions of capital from unconsolidated entities367 — 440 
Repayments on loan for natural gas liquids facilityRepayments on loan for natural gas liquids facility— — 3,022 
Net cash used in investing activities-continuing operationsNet cash used in investing activities-continuing operations(212,408)(221,493)(1,737,620)
Net cash provided by investing activities-discontinued operationsNet cash provided by investing activities-discontinued operations— — 298,864 
Net cash used in investing activitiesNet cash used in investing activities(212,408)(221,493)(1,438,756)
FINANCING ACTIVITIES:FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilitiesProceeds from borrowings under revolving credit facilities1,815,000 1,261,000 4,074,000 
Payments on revolving credit facilitiesPayments on revolving credit facilities(1,703,000)(2,727,000)(3,775,000)
Issuance of senior secured and unsecured notes and term credit agreementIssuance of senior secured and unsecured notes and term credit agreement— 2,300,000 700,000 
Repayment of term credit agreementsRepayment of term credit agreements— (555,562)— 
Repayment and repurchase of senior unsecured notesRepayment and repurchase of senior unsecured notes(83,167)(115,796)(454)
Proceeds from borrowings on other long-term debtProceeds from borrowings on other long-term debt— 50,000 — 
Payments on other long-term debtPayments on other long-term debt(7,390)(5,590)(653)
Debt issuance costsDebt issuance costs(12,932)(65,566)(14,950)
Distributions to general and common unit partners and preferred unitholdersDistributions to general and common unit partners and preferred unitholders— (142,128)(244,400)
Distributions to noncontrolling interest ownersDistributions to noncontrolling interest owners(1,635)(4,115)(1,145)
Proceeds from sale of preferred units, net of offering costsProceeds from sale of preferred units, net of offering costs— — 622,391 
Payments for redemption of preferred unitsPayments for redemption of preferred units— — (265,128)
Common unit repurchases and cancellationsCommon unit repurchases and cancellations(90)(182)(1,644)
Payments to settle contingent consideration liabilitiesPayments to settle contingent consideration liabilities(1,231)(95,437)(98,958)
Investment in NGL Energy Holdings LLCInvestment in NGL Energy Holdings LLC— — (15,226)
Net cash provided by (used in) financing activitiesNet cash provided by (used in) financing activities5,555 (100,376)978,833 
Net (decrease) increase in cash and cash equivalentsNet (decrease) increase in cash and cash equivalents(1,007)(17,875)4,132 
Cash and cash equivalents, beginning of periodCash and cash equivalents, beginning of period4,829 22,704 18,572 
Cash and cash equivalents, end of periodCash and cash equivalents, end of period$3,822 $4,829 $22,704 
Supplemental cash flow information:     Supplemental cash flow information:
Cash interest paid$170,632
 $192,938
 $117,912
Cash interest paid$254,814 $168,642 $155,445 
Income taxes paid (net of income tax refunds)$2,423
 $1,843
 $2,022
Income taxes paid (net of income tax refunds)$2,480 $2,586 $4,931 
Supplemental non-cash investing and financing activities:     Supplemental non-cash investing and financing activities:
Distributions declared but not paid to Class B preferred unitholders$4,725
 $4,725
 $
Distributions declared but not paid to preferred unitholdersDistributions declared but not paid to preferred unitholders$— $13,814 $18,687 
Accrued capital expenditures$19,121
 $12,123
 $1,758
Accrued capital expenditures$14,558 $21,824 $88,917 
Value of common units issued in business combinations$
 $
 $3,940
The accompanying notes are an integral part of these consolidated financial statements.

F-8
F-9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements


Note 11—Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At March 31, 2019,2022, our operations included:included 3 segments:

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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 trucking, marine and pipeline 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 owned and leased pipelines.
Our Water SolutionsLiquids Logistics segment provides servicesconducts supply operations for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms, drilling fluids and drilling muds and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services and sells freshwater to producers for exploration and production activities.
Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 27 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility joint venture in Utah. See Note 16 for a discussion of the joint venture of our Sawtooth Caverns, LLC (“Sawtooth”) business.
Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol,liquids, refined petroleum products and biodiesel marketing operations, purchases refined petroleumto a broad range of commercial, retail and renewable products primarily in the Gulf Coast, Southeast and Midwest regions ofindustrial customers across the United States and schedules themCanada. These operations are conducted through our 24 owned terminals, third-party storage and terminal facilities, 9 common carrier pipelines and a fleet of leased railcars. We also provide services for delivery at various locations throughout the country. In addition,marine exports of butane through our facility located in certain storage locations, our Refined ProductsChesapeake, Virginia, and Renewables segment may also purchase unfinished gasoline blending components for subsequent blending into finished gasolineexpect to supply our marketing business as well as third parties.

Recent Developments

On March 30, 2018, we sold a portion of our Retail Propane segment to DCC LPG (“DCC”) for net proceeds of $212.4 million in cash. The Retail Propane businesses subject to this transaction consisted of ourcommence operations across the Mid-Continent and Western portions of the United States. On July 10, 2018, we completed the sale of virtually all of our remaining Retail Propane segment to Superior Plus Corp. (“Superior”) for total consideration of $889.8 million in cash. We retained our 50% ownership interest in Victory Propane, LLC (“Victory Propane”), which we subsequently sold on August 14, 2018 (see Note 2). These transactions represent a strategic shift in our operations and will have a significant effect on our operations and financial results going forward. Accordingly, the results of operations and cash flows related to our former Retail Propane segment (including equitypropane pipeline in earnings of Victory Propane) have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjustedMichigan in the consolidated statements of operations and consolidated statements of cash flows. In addition, the assets and liabilities related to our former Retail Propane segment have been classified as held for sale within our March 31, 2018 consolidated balance sheet. See Note 17 for a further discussion of the transaction.June 2022.

Note 22—Significant Accounting Policies


Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The accompanying 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 consolidated financial statements.


F-10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Use of Estimates

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

Critical accounting estimates we make in the preparation of our consolidated financial statements include, among others, determining the fair valueimpairment of assetsgoodwill and liabilities acquired in acquisitions, the fair value of derivative instruments, the collectibility of accounts receivable, the recoverability of inventories,long-lived assets, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the impairmentfair value of long-lived assets and goodwill,derivative instruments, estimating certain revenues, the fair value of asset retirement obligations, the fair value of equity-based compensation,assets and liabilities acquired in acquisitions, the recoverability of inventories, the collectibility of accounts and notes receivable and accruals for environmental matters and estimating certain revenues.matters. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

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

F-9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Level 1: Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level 2: Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and forward commodity contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
Level 3: Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain physical contracts that qualify for the normal purchase and normal sale election. Under this accounting policy election,transactions that are expected to result in physical delivery. For these transactions, 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.

We have not designated any financial instruments as hedges for accounting purposes. 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled.

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

F-11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


movements. Inherent in the resulting contractual portfolio are certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Cost of Sales

We include all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory, prior to delivery to our customers, in cost of sales. Cost of sales excludes depreciation of our property, plant and equipment.

Depreciation and Amortization

Depreciation and amortization in our consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded
F-10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

to interest expense and certain contract-based intangible assets, for which the amortization is recorded to either cost of sales.sales or operating expense.

Income Taxes

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

We have certain taxable corporate subsidiaries in the United States and Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 20152018 to 20182021 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amountsvalue of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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

initial public offering.
During the year ended March 31, 2019, we recognized
We have a deferred tax liability of $16.3$43.5 million and $45.8 million at March 31, 2022 and 2021, respectively, as a result of acquiring a corporationcorporations in connection with onecertain of our acquisitions, (see Note 4).which is included within other noncurrent liabilities in our 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 forduring the year ended March 31, 2019 is $1.52022 was $1.2 million with an effective tax rate of 31%11.3%. The deferred tax liability is $14.8 million atbenefit recorded during the year ended March 31, 2019 and is included within other noncurrent liabilities in our consolidated balance sheet.2021 was $4.7 million with an effective tax rate of 39.7%.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our consolidated financial statements at March 31, 20192022 or 2018.2021.


F-12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested inManagement considers all highly liquid instrumentsinvestments with maturitiesa maturity of three months or less, atwhen purchased, to be cash equivalents. We place our cash and cash equivalents with financial institutions that are insured by the dateFederal Deposit Insurance Corporation; however, we maintain deposits in banks which exceed the amount of purchase. At times, certain account balances may exceed federally insured limits.deposit insurance available. Management routinely assesses the financial condition of the institutions and believes that any possible credit loss would be minimal.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. TheSee Note 16 for a further discussion of our allowance for doubtful accounts is based on our assessment of the collectibility of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.expected credit losses.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

Our accounts receivable consistCITGO Petroleum Corporation accounted for 12.8% of our consolidated revenues for the year ended March 31, 2022. The majority of the following at the dates indicated:revenue for this customer pertains to our Crude Oil Logistics segment activities, and sales to this customer
  March 31, 2019 March 31, 2018
Segment Gross
Receivable
 Allowance for
Doubtful
Accounts
 Net Gross
Receivable
 Allowance for
Doubtful
Accounts
 Net
  (in thousands)
Crude Oil Logistics $514,243
 $(15) $514,228
 $404,865
 $
 $404,865
Water Solutions 57,526
 (3,157) 54,369
 59,958
 (2,952) 57,006
Liquids 134,050
 (177) 133,873
 131,006
 (20) 130,986
Refined Products and Renewables 461,050
 (1,017) 460,033
 435,136
 (1,229) 433,907
Corporate and Other 416
 
 416
 
 
 
Total $1,167,285
 $(4,366) $1,162,919
 $1,030,965
 $(4,201) $1,026,764
F-11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Changesoccur mainly out of our crude oil terminal in the allowance for doubtful accounts are as follows for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Allowance for doubtful accounts, beginning of period $(4,201) $(3,954) $(5,963)
Provision for doubtful accounts (369) (590) 1,000
Write off of uncollectible accounts 204
 343
 1,009
Allowance for doubtful accounts, end of period $(4,366) $(4,201) $(3,954)


Amounts in the tables above do not include accounts receivable or allowance for doubtful accounts related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet and the activity has been included within discontinued operations within our consolidated statements of operations (see Note 17).

Cushing, Oklahoma. We did not have any customers that represented over 10% of consolidated revenues for fiscalthe years 2019, 2018ended March 31, 2021 and 2017.2020.

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.


F-13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Inventories consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Crude oil$135,485 $64,916 
Propane43,971 45,521 
Butane33,144 19,189 
Biodiesel20,474 16,169 
Diesel3,504 2,252 
Ethanol3,503 3,056 
Other11,196 7,364 
Total$251,277 $158,467 
  March 31,
  2019 2018
  (in thousands)
Crude oil $51,359
 $77,351
Natural gas liquids:    
Propane 33,478
 38,910
Butane 15,294
 12,613
Other 7,482
 6,515
Refined products:    
Gasoline 189,802
 253,286
Diesel 103,935
 113,939
Renewables:    
Ethanol 51,542
 38,093
Biodiesel 10,251
 10,596
Total $463,143
 $551,303


Amounts in the table above do not include inventory related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

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. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the net assets of the investee. We consider distributions received from unconsolidated entities which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in our consolidated statements of cash flows. We consider distributions received from unconsolidated entities in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in our consolidated statements of cash flows.

Our investments inAt March 31, 2022, cumulative equity earnings and cumulative distributions of our unconsolidated entities consist of the following at the dates indicated:since they were acquired were $6.5 million and $9.4 million, respectively.
    Ownership Date Acquired March 31,
Entity Segment Interest (1) or Formed 2019 2018
        (in thousands)
Water services company (2) Water Solutions 50% August 2018 $920
 $
Natural gas liquids terminal company (3) Liquids 50% March 2019 207
 
Water treatment and disposal facility (4) Water Solutions —% August 2015 
 2,094
E Energy Adams, LLC (5) Refined Products and Renewables —% December 2013 
 15,142
Victory Propane (6) Corporate and Other —% April 2015 
 
Total       $1,127
 $17,236

F-12
(1)Ownership interest percentages are at March 31, 2019.
(2)This is an investment in an unincorporated joint venture that we acquired as part of an acquisition in August 2018. See Note 4 for a further discussion.
(3)This is an investment in an unincorporated joint venture that we acquired as part of an acquisition in March 2019. See Note 4 for a further discussion.

F-14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Our investments in unconsolidated entities consist of the following at the dates indicated:
March 31,
EntitySegmentOwnership Interest20222021
(in thousands)
Water services and land companyWater Solutions50%$15,714 $15,832 
Water services and land companyWater Solutions10%2,863 3,254 
Water services and land companyWater Solutions50%2,210 2,284 
Aircraft company (1)Corporate and Other50%538 748 
Water services companyWater Solutions50%409 424 
Natural gas liquids terminal companyLiquids Logistics50%163 177 
Total$21,897 $22,719 
(4)This is an investment in an unincorporated joint venture. On February 28, 2019, we sold this investment as part of the sale of our South Pecos water disposal business. See Note 16 for a further discussion.
(5)On May 3, 2018, we sold our previously held 20% interest in E Energy Adams, LLC for net proceeds of $18.6 million and recorded a gain on disposal of $3.0 million during the year ended March 31, 2019 within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations.
(6)On August 14, 2018, we sold our previously held 50% interest in Victory Propane. See Note 13 for a further discussion.

Combined summarized financial information(1)    This is an investment with a related party. See Note 12 for all of our unconsolidated entities is as follows for the dates and periods indicated:a further discussion.

Balance sheets:
 March 31,
 2019 2018
 (in thousands)
Current assets$1,328
 $24,431
Noncurrent assets$519
 $99,164
Current liabilities$178
 $16,787
Noncurrent liabilities$
 $10,620

Statements of operations:
 March 31,
 2019 2018 2017
 (in thousands)
Revenues$21,036
 $182,820
 $180,632
Cost of sales$9,919
 $114,890
 $114,316
Net income$5,506
 $26,438
 $19,462


At March 31, 2019, cumulative equity earnings and cumulative distributions of our unconsolidated entities since they were acquired were $1.9 million and $3.0 million, respectively.

Variable Interest Entity

Victory Propane was formed as a joint venture in April 2015 by us and an unrelated third party. The business purpose of Victory Propane is to acquire and/or develop retail propane operations in a defined geographic area. In conjunction with the formation of Victory Propane, we agreed to provide Victory Propane a revolving line of credit of $5.0 million and have concluded that Victory Propane is a variable interest entity because the equity of Victory Propane is not sufficient to fund its activities without additional subordinated financial support. On August 14, 2018, we sold our interest in Victory Propane. Our equity in earnings in Victory Propane has been classified within discontinued operations, as discussed further in Note 1 and Note 17.

F-15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
  March 31,
  2019 2018
  (in thousands)
Loan receivable (1) $19,474
 $29,463
Line fill (2) 33,437
 34,897
Tank bottoms (3) 44,148
 42,044
Minimum shipping fees - pipeline commitments (4) 23,494
 88,757
Other 39,451
 49,878
Total $160,004
 $245,039
March 31,
20222021
(in thousands)
Linefill (1)$28,065 $28,110 
Minimum shipping fees - pipeline commitments (2)8,899 13,171 
Loan receivable (3)3,147 2,962 
Other5,691 6,490 
Total$45,802 $50,733 
(1)Represents the noncurrent portion of a loan receivable associated with our financing of the construction of a natural gas liquids facility that is utilized by a third party and the noncurrent portion of a loan receivable with Victory Propane (see Note 13).
(2)
(1)    Represents minimum volumes of product we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At March 31, 2019, line fill consisted of 335,069 barrels of crude oil and 262,000 barrels of propane. At March 31, 2018, line fill consisted of 360,425 barrels of crude oil and 262,000 barrels of propane. Line fill held in pipelines we own is included within property, plant and equipment (see Note 5).
(3)Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At March 31, 2019 and 2018, tank bottoms held in third party terminals consisted of 389,737 barrels and 366,212 barrels of refined products, respectively. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).
(4)Represents the minimum shipping fees paid in excess of volumes shipped, or deficiency credits, for two contracts with crude oil pipeline operators. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 9). During the three months ended June 30, 2018, we entered into a definitive agreement, as described further in Note 13, in which we agreed to provide the benefit of our deficiency credit under one of these contracts. As a result of providing this benefit to the third party, we wrote off $67.7 million of these deficiency credits and recorded a loss within loss (gain) on disposal or impairment of assets, net. Under the remaining other contract for which we have the future benefit, we currently have 13 months in which to ship the excess volumes.

Amounts in the table above do not include other noncurrent assets related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 20182022 and 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). During the three months ended March 31, 2020, we recorded an impairment of $7.7 million primarily due to adjusting the cost basis of pipeline linefill to the market price of propane as of March 31, 2020.
(2)    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 8). As of March 31, 2022, the deficiency credit was $13.2 million, of which $4.3 million is recorded within prepaid expenses and other current assets in our consolidated balance sheet (see Note 17).sheet.
(3)    Represents the noncurrent portion of a loan receivable, net of an allowance for an expected credit loss, with a former related party.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:
  March 31,
  2019 2018
  (in thousands)
Accrued compensation and benefits $19,558
 $18,033
Excise and other tax liabilities 40,339
 40,829
Derivative liabilities 100,372
 51,039
Accrued interest 24,882
 39,947
Product exchange liabilities 21,081
 11,842
Gavilon legal matter settlement (Note 9) 12,500
 
Deferred gain on sale of general partner interest in TLP (1) 
 30,113
Other 29,718
 31,701
Total $248,450
 $223,504

(1)See Note 15 for a discussion of the accounting for the deferred gain upon adoption of ASC 606.


F-16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Amounts in the table above do not include accrued expenses and other payables related to our former Retail Propane segment, as these amounts have been classified as liabilities held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

March 31,
20222021
(in thousands)
Accrued interest$56,104 $56,299 
Derivative liabilities27,108 21,562 
Accrued compensation and benefits18,417 41,456 
Excise and other tax liabilities10,451 10,970 
Product exchange liabilities853 1,188 
Other27,786 38,925 
Total$140,719 $170,400 
Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included within loss (gain) on disposal or impairment of
F-13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

assets, net. We compute depreciation expense of our property, plant and equipment using the straight-line method over the estimated useful lives of the assets (see Note 54).
).

Intangible Assets

Recent Accounting Pronouncements
Our intangible assets include contracts
For a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our consolidated financial statements included in this Annual Report.

Critical Accounting Estimates

The preparation of financial statements and arrangements acquiredrelated disclosures in business combinations, including customer relationships, customer commitments, pipeline capacity rights, rights-of-wayconformity with GAAP requires the selection and easements, water rights, executory contractsapplication of appropriate accounting principles to the relevant facts and other agreements, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs associated with the revolving credit facilities. We amortize the majoritycircumstances of our intangible assetsoperations and the use of estimates made by management. We have identified the following more critical judgment areas in the application of our 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.

Impairment of Goodwill

The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred. For each reporting unit, we perform a straight-line basis overqualitative assessment of relevant events and circumstances about the estimated useful liveslikelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the assets (see Note 7). We amortize debt issuance costs overreporting unit is less than its carrying value, we calculate the termsfair value of the related debt usingreporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewing several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a methodreporting unit. The determination of a reporting unit’s fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that approximatescan materially affect our estimates. If the effective interest method.fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, an impairment loss is recognized to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value, limited to the total amount of goodwill for the reporting unit. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. During the years ended March 31, 2021 and 2020, we recorded goodwill impairments of $237.8 million and $250.0 million, respectively. We did not record a goodwill impairment during the year ended March 31, 2022. See Note 5 to our consolidated financial statements included in this Annual Report for a further discussion of our goodwill impairment assessment.

Impairment of Long-Lived Assets

We evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. InIndividual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans as well as external factors such as industry and economic trends. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that event, we recognize a loss equal to the amount by whichcan materially affect our estimates. If the carrying value exceedsis not recoverable, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. See Note 4 and Note 6 to our consolidated financial statements included in this Annual Report for a further discussion of our impairments of long-lived assets.
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We evaluate our investments in unconsolidated entities for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the fair value of such investment may have experienced a decline to less than its carrying value and the decline is other than temporary.

Depreciation and Amortization Methods and Estimated Useful Lives of Property, Plant and Equipment and Intangible Assets

Depreciation and amortization expense is the systematic write-off of the cost of our property, plant and equipment (net of residual or salvage value, if any) and the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate our property, plant and equipment and amortize the majority of our intangible assets using the straight-line method, which results in our recording depreciation and amortization expense evenly over the estimated life of the individual asset. The estimate of depreciation and amortization expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipment in service or acquire intangible assets, we develop assumptions about the useful economic lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation and amortization expense prospectively and have a material impact on our results of operations. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, changes in expected salvage values or changes in customer attrition rates. See Note 2, Note 4 and Note 6 to our consolidated financial statements included in this Annual Report for a further discussion.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for normal purchase and normal sale transactions that are expected to result in physical delivery. Changes in the fair value are recorded within revenue (for sales contracts) or cost of sales (for purchase contracts) in our consolidated statements of operations. We determine the fair value of our exchange traded derivative financial instruments utilizing publicly available prices, and for non-exchange traded derivative financial instruments, we utilize pricing models for similar instruments including publicly available prices and forward curves generated from a compilation of data gathered from third parties. Actual amounts could vary materially from estimated fair values due to changes in market prices. In addition, changes in the methods or assumptions used to determine the fair value of our derivative financial instruments could have a material effect on our consolidated financial statements. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk to see the impact of a 10% increase in the underlying commodity value and Note 2 and Note 10 to our consolidated financial statements included in this Annual Report for a further discussion of our derivative financial instruments.

Revenue Recognition

Our Water Solutions segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our corresponding performance obligation, and the difference in timing of revenue recognition and billings results in contract assets and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management including volume and forecasted production information. Changes in these assumptions or a contract modification could have a material effect on the amount of variable consideration recognized as revenue. See Note 14 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies.

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 largest asset retirement obligations involve the abandonment or removal of pipelines and saltwater and freshwater disposal wells. We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. Most of these retirement obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. These estimates and assumptions are very subjective and can vary
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over time. Our consolidated balance sheet at March 31, 2022 includes a liability of $29.9 million related to asset retirement obligations, which is reported within other noncurrent liabilities.

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 group. When we cease to useretirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminable. We will record an acquired trade name, we test the trade nameasset retirement obligation for impairment using the relief from royalty method and we begin amortizing the trade name over its estimated useful life as a defensive asset. See Note 5 and Note 7 for a further discussion of long-lived asset impairments recognizedthese assets in the consolidated statements of operations.

We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary.

Goodwill

Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities assumed. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that all of our goodwill at March 31, 2019 is deductible for federal income tax purposes.

Goodwill and indefinite-lived intangible assets are not amortized, but instead are evaluated for impairment at least annually. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant.

To perform this assessment, we first consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit does not exceed its carrying amount, we calculate the fair value for the reporting unit and compare the amount to its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, goodwill is considered to be impaired and the goodwill balance is reduced by the difference between the fair value and carrying amount of the reporting unit.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual goodwill impairment assessment included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. See Note 6 for a further discussion and analysis of our goodwill impairment assessment.


F-17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets and within accrued expenses and other payables in our consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials. Product exchanges related to our former Retail Propane segment have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrolling interests are reported as a component of equity, unless the noncontrolling interest is considered redeemable,periods in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in our consolidated balance sheet. The redeemable noncontrolling interest is adjusted at each balance sheet date to its maximum redemption value if the amount is greater than the carrying value. The redeemable noncontrolling interest is included in liabilities and redeemable noncontrolling interest held for sale in our consolidated balance sheets (see Note 17). The following table summarizes changes in our redeemable noncontrolling interest in our consolidated balance sheets (in thousands):settlement dates are reasonably determinable.
Balance at March 31, 2017 $3,072
Net income attributable to redeemable noncontrolling interest 1,030
Redeemable noncontrolling interest valuation adjustment 5,825
Balance at March 31, 2018 9,927
Net loss attributable to redeemable noncontrolling interest (446)
Redeemable noncontrolling interest valuation adjustment 3,349
Disposal of redeemable noncontrolling interest (12,830)
Balance at March 31, 2019 $


Acquisitions

To determine if a transaction should be accounted for as a business combination or an acquisition of assets, we first calculate the relative fairFair values of the assets acquired. If substantially all of the relative fair value is concentrated in a single asset or group of similar assets, or if not but the transaction does not include a significant process (does not meet the definition of a business), we record the transaction as an acquisition of assets. For acquisitions of assets, the purchase price is allocated based on the relative fair values. For an acquisition of assets, goodwill is not recorded. All other transactions are recorded as business combinations. We record the assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in a business combination at theirthe allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, datesuch as through depreciation and amortization expense. While we believe we have made reasonable assumptions to calculate the fair values.value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. For a business combination, the excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but instead is evaluated for impairment at least annually (as described above).

annually. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination.

Inventories

Our inventories consist of crude oil, natural gas liquids, diesel, ethanol and biodiesel. 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. At the end of each fiscal year, we also perform a “lower of cost or net realizable value” analysis; if the cost basis of the inventories would not be recoverable based on the net realizable value at the end of the year, we reduce the book value of the inventories to the recoverable amount. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or net realizable value write-down if we expect the net realizable value to recover by our fiscal year end. The net realizable values of these commodities change on a daily basis as supply and demand conditions change. We are unable to control changes in the net realizable value of these commodities and are unable to determine whether write-downs will be required in future periods.

Item 7A.    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, which has since been determined to be an adjusted forward-looking term rate based on the secured overnight financing rate). At March 31, 2022, we had $116.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 4.64%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.1 million, based on borrowings outstanding at March 31, 2022.

In addition, on and after certain dates, distributions for our Class B Preferred Units and Class C Preferred Units will be calculated using the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) 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 alternative rate as determined in the partnership agreement) plus a spread of 7.213%. For our Class C Preferred Units, distributions on and after April 15, 2024 will
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accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) 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 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled. See “Critical Accounting Estimates” above for a discussion of how we determine the fair value of our financial derivative instruments.

The following table summarizes the hypothetical impact on the March 31, 2022 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 (Water Solutions segment)$(4,838)
Crude oil (Crude Oil Logistics segment)$(8,612)
Propane (Liquids Logistics segment)$532 
Butane (Liquids Logistics segment)$(3,026)
Refined Products (Liquids Logistics segment)$(2,598)
Other Products (Liquids Logistics segment)$4,106 

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 try to 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;
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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.

At March 31, 2022, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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Item 8.    Financial Statements and Supplementary Data

Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the report of Grant Thornton LLP, our independent registered public accounting firm, are incorporated by reference into this Item 8.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure 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 the 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 (“SEC”) 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 March 31, 2022. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2022, such disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting

The management of our Delaware limited partnership (the “Partnership”) and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO framework.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2022.

Our internal control over financial reporting as of March 31, 2022 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report, which appears below in this section of the Annual Report.

Changes in Internal Control Over Financial Reporting

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 March 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2022, and our report dated June 6, 2022 expressed an unqualified opinion on those financial statements.

Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
June 6, 2022


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Item 9B.    Other Information

None.

Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Board of Directors of our General Partner

NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

The board of directors of our general partner currently has eight members. The board of directors of our general partner has determined that Mr. James M. Collingsworth, Mr. Stephen L. Cropper, Mr. Bryan K. Guderian and Mr. Derek S. Reiners satisfy the New York Stock Exchange (“NYSE”) and Securities and Exchange Commission (“SEC”) independence requirements. The NYSE does not require a listed publicly traded limited partnership like NGL to have a majority of independent directors on the board of directors of its general partner. In addition, we are not required to have a nominating and corporate governance committee.

In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

experience in business, government, education, technology or public interests;
high-level managerial experience in large organizations;
breadth of knowledge regarding our business and industry;
specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
moral character and integrity;
commitment to our unitholders’ interests;
ability to provide insights and practical wisdom based on experience and expertise;
ability to read and understand financial statements; and
ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

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Directors and Named Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Named executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The following table summarizes information regarding the directors of our general partner and our named executive officers as of June 1, 2022. 
NameAgePosition with NGL Energy Holdings LLC
H. Michael Krimbill68Chief Executive Officer and Director
Linda J. Bridges38Executive Vice President and Chief Financial Officer
John A. Ciolek58Executive Vice President, Strategic Initiatives
Kurston P. McMurray50Executive Vice President and General Counsel and Secretary
Lawrence J. Thuillier51Chief Accounting Officer
Shawn W. Coady60Director
James M. Collingsworth67Director
Stephen L. Cropper72Director
Bryan K. Guderian62Director
John T. Raymond51Director
Derek S. Reiners51Director
Randall S. Wade52Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007, Williams Partners L.P. from 2007 to September 2012, and Pacific Commerce Bank from January 2011 to March 2015.

Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating midstream businesses. Mr. Krimbill also brings financial expertise to the board, including his prior service as a chief financial officer. Mr. Krimbill’s experience serving on other public company boards is also a valuable asset to our board of directors.

Linda J. Bridges. Ms. Bridges has served as our Executive Vice President and Chief Financial Officer since September 30, 2021. Ms. Bridges served as our Senior Vice President, Finance and Treasurer from April 2018 to September 2021. She joined the general partner in June 2016, as Vice President of Finance and Treasurer until she was promoted. Ms. Bridges spent nine years in the commercial division at the Bank of Oklahoma, holding various positions including Vice President - Energy Lending.

John A. Ciolek. Mr. Ciolek joined us in December 2019 and was appointed as our Executive Vice President, Strategic Initiatives, by the board of directors of our general partner in January 2020. Prior to joining NGL, Mr. Ciolek served as Managing Director in the Oil and Gas Group at Credit Suisse Securities LLC (“Credit Suisse”) from August 2015 to October 2019. Before joining Credit Suisse, he served as the Head of the Midstream Franchise within J.P. Morgan’s North American Energy Group starting in May 2011. He previously served for 14 years with Citigroup’s Global Energy Group.

Kurston P. McMurray. Mr. McMurray has served as our Executive Vice President and General Counsel and Secretary since October 2016. Mr. McMurray joined NGL in February 2015 as Vice President, Legal and Corporate Secretary. Prior to joining NGL, Mr. McMurray practiced law in the Tulsa, Oklahoma area since 1998 at firms including Moyers, Martin, Santee, Imel & Tetrick LLP. and Robinett & Osmond and was a founding shareholder of Kurston P. McMurray, PC and Wilkin/McMurray PLLC. Mr. McMurray’s private practice specialized in business transactions, real estate, construction, healthcare, banking, corporate governance, corporate management and commercial litigation.

Lawrence J. Thuillier. Mr. Thuillier has served as our Chief Accounting Officer since January 2016. Prior to joining NGL, Mr. Thuillier served in various roles at Eagle Rock Energy Partners, L.P. from December 2007 through October 2015, most recently as Vice President of Financial Reporting and Corporate Controller. Mr. Thuillier served as Assistant Corporate
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Controller for Exterran Holdings, Inc. (formerly Universal Compression) from November 2006 through November 2007. Prior to that, Mr. Thuillier served in various roles at Deloitte & Touche LLP, most recently as Audit Senior Manager.

Shawn W. Coady. Dr. Coady served as our President and Chief Operating Officer, Retail Division, from April 2012 to March 2018, when we sold a portion of our Retail Propane segment to DCC LPG (“DCC”), and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady served as an executive officer of DCC from April 2018 until his retirement in December 2020. Dr. Coady served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), from March 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicksgas LLC, and the membership interests in Hicksgas LLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until the membership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National Propane Gas Association from 2004 to 2015 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.

Dr. Coady brings valuable operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

James M. Collingsworth. Mr. Collingsworth has served on the board of directors of our general partner since January 2015. Mr. Collingsworth previously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through January 2014. Prior to that, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior to joining Texaco, Mr. Collingsworth was director of feedstocks for Rexene Petrochemical Company from 1988 to 1991 and served in the MAPCO, Inc. organization from 1973 to 1988 in various capacities, including customer service and business development manager of the Mid-America and Seminole pipelines. Mr. Collingsworth served as a director of American Ethane Co. Mr. Collingsworth currently serves on the board of directors of Martin Midstream Partners L.P.

Mr. Collingsworth brings a wealth of in-depth industry experience to the board. Mr. Collingsworth has worked in all facets of the midstream and petrochemical industry for more than 40 years.

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners, L.P. from 2000 through 2005. Since Mr. Cropper’s retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., Berry Petroleum Company, Rental Car Finance Corp., a subsidiary of Dollar Thrifty Automotive Group and Wawa Inc. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation.

Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian currently serves as a Principal of BKG Consulting LLC, an energy related consulting firm. Mr. Guderian has served as Executive Vice President of Business Development of WPX Energy, Inc. (“WPX”) from February 2018 until his retirement in January 2021. Mr. Guderian served as Senior Vice President of Business Development of WPX from October 2014 to February 2018 and as Senior Vice President of Operations of WPX from August 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian served as a director of Apco Oil & Gas International Inc., from 2002 to 2015 and as a director of Petrolera Entre Lomas S.A. from 2003 to 2015.

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

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John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group (“EMG”) of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

Mr. Raymond also currently serves as a director of Ferus Inc., Ferus Natural Gas Fuels Inc., MarkWest Utica EMG, LLC, Medallion Midstream, LLC and PAA GP Holdings LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC.

Mr. Raymond brings extensive financial and industry experience to the board. As a director for other public companies, Mr. Raymond also provides cross board experience.

Derek S. Reiners. Mr. Reiners joined the board of directors of our general partners in December 2019 and was appointed to serve on the Audit Committee. Mr. Reiners currently serves as the President of Contango Energy Capital LLC, a privately held investment and consulting firm. Prior to that, Mr. Reiners served in various senior financial and accounting roles at ONEOK, Inc. and ONEOK Partners, L.P. from August 2009 to May 2019, including Senior Vice President and Chief Accounting Officer from August 2009 to December 2012, Senior Vice President, Chief Financial Officer from January 2013 to May 2017 and Senior Vice President, Finance and Treasurer from June 2017 to May 2019. Prior to joining ONEOK, Mr. Reiners was a partner at Grant Thornton LLP from August 2004 to July 2009. Mr. Reiners is a certified public accountant.

Mr. Reiners brings extensive executive, financial and operational experience to the board. With over ten years of experience in the natural gas liquids industry in numerous positions, Mr. Reiners provides valuable insight into our business and industry.

Randall S. Wade. Mr. Wade has served on the board of directors of our general partner since February 2021. Mr. Wade is the President of EIG Global Energy Partners (“EIG”) and a member of its Investment and Executive Committees. He has broad involvement in the firm’s various activities including investments, investor relations, operations and strategic initiatives. Since joining EIG in 1996, Mr. Wade has filled various roles including Chief Operating Officer, head of the direct lending strategy, investment principal with coverage responsibility for Australia and an analyst for the oil and gas team. Prior to joining EIG, Mr. Wade was a Commercial Lending Officer for First Interstate Bank of Texas, where he was responsible for developing a middle-market loan portfolio.

Mr. Wade brings extensive financial and industry experience to the board.

Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors of our general partner. EMG NGL HC LLC has the right to designate one person to serve on the board of directors of our general partner, and has designated John T. Raymond. EIG has the right to designate one person to serve on the board of directors of our general partner, and has designated Randall S. Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and his brother Todd M. Coady) and the investors who formed the Partnership (“IEP Parties”) (which consists of certain entities controlled by H. Michael Krimbill, and two other investors) each have the right to designate one person to serve on the board of directors of our general partner. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman, although our chief executive officer, Mr. Krimbill, presides over the meetings.

The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors regarding its respective risk oversight role.
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Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

retain and terminate our independent registered public accounting firm;
approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and
establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Mr. Collingsworth, Mr. Cropper, Mr. Guderian, and Mr. Reiners currently serve on the audit committee, and Mr. Reiners serves as the chairman. The board of directors of our general partner has determined that Mr. Reiners is an “audit committee financial expert” as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE and Exchange Act rules.

Compensation Committee

The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include the following, among others:

establishing the general partner’s compensation philosophy and objectives;
approving the compensation of the Chief Executive Officer and other officers;
making recommendations to the board of directors with respect to the directors; and
reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based compensation plans.

Mr. Collingsworth, Mr. Cropper, and Mr. Guderian currently serve on the compensation committee, and Mr. Cropper serves as the chairman. The board of directors of our general partner has determined that Mr. Cropper, Mr. Collingsworth and Mr. Guderian are independent directors under applicable NYSE and Exchange Act rules.

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate Controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

We make available free of charge, within the “Governance” section of our website at www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. Reiners presides over these executive sessions.

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.

Item 11.    Executive Compensation

Compensation Discussion and Analysis

The year “2022” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2022.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. The board of directors has formed a compensation committee to develop our compensation program and to approve the compensation of the Chief Executive Officer and other officers. Our executive officers are also officers of our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our “named executive officers” for fiscal year 2022 were:

H. Michael Krimbill–Chief Executive Officer
Linda J. Bridges–Executive Vice President and Chief Financial Officer (effective September 30, 2021)
Lawrence J. Thuillier–Chief Accounting Officer
Kurston P. McMurray–Executive Vice President and General Counsel and Secretary
John A. Ciolek–Executive Vice President, Strategic Initiatives
Robert W. Karlovich III–Former Executive Vice President and Chief Financial Officer (resigned effective September 30, 2021)

Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer’s contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

Our executive compensation program is designed to provide a total compensation package that allows us to:

Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;
Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and
Reward success in reaching those goals.

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Factors Enhancing Alignment with Unitholder Interests

At risk incentive compensation based on annual financial performance and growth in unitholder value;
No excise tax gross-ups; and
Compensation committee engages an independent compensation adviser.

Compensation Setting Process
Our compensation program for our named executive officers supports our philosophy of pay-for-performance.
Role of Management: Our Chief Executive Officer provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our named executive officers, other than his own.
Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. In March 2021, the compensation committee received compensation advice and data from Pearl Meyer & Partners (“PM&P”). PM&P provided advice and guidance regarding the principal components of compensation for our directors and market salary information for certain executive and senior vice president positions. The compensation committee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted the following:

PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;
PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
Fees paid to PM&P by the Partnership for the services provided in March 2021 were less than 1% of PM&P’s total revenue;
None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;
None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and
None of the PM&P consultants working on Partnership matters own Partnership interests.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis.

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Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. The following table summarizes the primary elements of compensation in our executive compensation program: 
Objective Supported
ElementPrimary PurposeHow Amount DeterminedAttract &
Retain
Motivate &
Pay-for-
Performance
Unitholder
Alignment
Base Salary
Fixed income to compensate executive officers for their level of responsibility, expertise and experience
Based on competition in the marketplace for executive talent and abilities
X
Discretionary Cash Bonus Awards
Rewards achievement of specific annual financial and operational performance goals
Based on the named executive officer’s relative contribution to the ongoing business of the Partnership
XXX
Recognizes individual contributions to our performance
Long-Term Equity Incentive Awards
Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders
Based on the named executive officer’s expected contribution to long-term performance goals
XXX
Provides a forfeitable long-term incentive to encourage executive retention

Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.
Our named executive officers are entitled to the following annual base salaries:
NameFiscal Year Ended
March 31, 2021
Base Salary Rate($)(1)
Fiscal Year Ended
March 31, 2022
Base Salary Rate($)(2)
H. Michael Krimbill625,000 625,000 
Linda J. Bridges— 500,000 
Lawrence J. Thuillier300,000 312,000 
Kurston P. McMurray500,000 500,000 
John A. Ciolek500,000 500,000 
Robert W. Karlovich III500,000 500,000 
(1)    Messrs. Thuillier and McMurray’s base salary rates became effective March 28, 2021. All other named executive officers’ base salary rates were effective April 1, 2020, other than Ms. Bridges who was not serving as a named executive officer during the relevant fiscal year.
(2)    Ms. Bridges base salary rate became effective with her appointment to Executive Vice President and Chief Financial Officer on September 30, 2021. Mr. Thuillier’s base salary rate became effective on January 16, 2022. Mr. Karlovich’s base salary rate for the fiscal year was prorated through September 30, 2021, the date of his resignation from employment. All other named executive officers’ base salary rates were effective April 1, 2021.

Discretionary Cash Bonus Awards

None of the named executive officers is subject to a formal cash bonus plan, and any cash bonuses are at the discretion of the compensation committee of the board of directors. During fiscal year 2022, cash bonuses of $0.3 million were paid to
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both Mr. Ciolek and Mr. McMurray and cash bonuses of $0.2 million were paid to both Ms. Bridges and Mr. Thuillier. Neither Mr. Krimbill nor Mr. Karlovich received a cash bonus during fiscal year 2022.

Long-Term Equity Incentive Awards

The Partnership previously adopted a long-term incentive plan (“LTIP”), which allowed for the issuance of equity-based compensation. The LTIP expired with respect to future awards on May 10, 2021. Prior to expiring, on May 5, 2021, the compensation committee of our board of directors granted certain restricted units to the named executive officers, which vest in tranches, subject to the continued service of the recipients through the vesting date (the “Service Awards”). See “2022 Grants of Plan Based Awards” for details about the number of restricted Service Award units granted in fiscal year 2022 and the relevant vesting terms.

The following table summarizes Service Award units activity for all outstanding Service Award grants during fiscal year 2022 with respect to the named executive officers:
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits VestedUnits ForfeitedMarch 31, 2022
H. Michael Krimbill (1)75,000 250,000 (137,500)— 187,500 
Linda J. Bridges (2)6,250 100,000 (31,250)— 75,000 
Lawrence J. Thuillier (3)5,000 55,000 (18,750)— 41,250 
Kurston P. McMurray (4)10,000 150,000 (47,500)— 112,500 
John A. Ciolek (5)12,500 150,000 (50,000)— 112,500 
Robert W. Karlovich III (6)12,500 150,000 — (162,500)— 
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022. He was granted 250,000 Service Awards on May 5, 2021.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022. She was granted 100,000 Service Awards on May 5, 2021.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022. He was granted 55,000 on May 5, 2021.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(6)    Mr. Karlovich was granted 150,000 Service Awards on May 5, 2021. He forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

The following table summarizes the vesting dates of unvested Service Award units at March 31, 2022:
Units by Vesting DateUnvested Units at
NameNovember 14, 2022February 13, 2023November 15, 2023March 31, 2022
H. Michael Krimbill62,500 62,500 62,500 187,500 
Linda J. Bridges25,000 25,000 25,000 75,000 
Lawrence J. Thuillier13,750 13,750 13,750 41,250 
Kurston P. McMurray37,500 37,500 37,500 112,500 
John A. Ciolek37,500 37,500 37,500 112,500 
Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers, other than to Mr. McMurray, who is entitled to receive severance benefits pursuant to his employment agreement in the event of certain terminations of his employment (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”). The board of directors has the option to accelerate the vesting of the Service Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of Service Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the “Outstanding Equity Awards at March 31, 2022” table below (in the “Market Value of Service Award Units that Have Not Yet Vested” column).
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401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. For every dollar that employees contribute up to 4% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employees contribute between 4% and 6% of their eligible compensation (as defined in the plan). Our matching contributions vest over an employee’s first two years of employment, subject to a participant’s continued service.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We offer a benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, vision, disability and life insurance.

Other Officers

Certain officers who have leadership roles within our individual business segments, but who are not executive officers, participate in formulaic bonus programs that are based on the performance of the individual business segments with which they are involved. In most cases, similar programs were in place prior to our acquisition of the businesses, and we have left the programs substantially intact.

Employment Agreements

We do not have employment agreements with any of our named executive officers, other than Mr. McMurray (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”).

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Internal Revenue Code of 1986, as amended.

Compensation Committee Report

The compensation committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on this review and discussion, the compensation committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this Annual Report. 
Members of the Compensation Committee:
Stephen L. Cropper (Chairman)
James M. Collingsworth
Bryan K. Guderian

Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of executive compensation, as the restricted units are designed to reward the executive officers based on the long-term performance of the Partnership. In combination with our risk management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

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Compensation Committee Interlocks and Insider Participation

During fiscal year 2022, James M. Collingsworth, Stephen L. Cropper, and Bryan K. Guderian served on the compensation committee. None of these individuals is an employee or an officer of our general partner.

Summary Compensation Table

The following table summarizes the compensation earned by our named executive officers for fiscal years 2020 through 2022. 
Name and Position Fiscal
Year
Salary
($)
Bonus
($)
Restricted Unit
Awards
(Service Awards) (1)
($)
All Other
Compensation (2)
($)
Total
($)
H. Michael Krimbill2022625,000 — 537,500 15,719 1,178,219 
Chief Executive Officer2021625,000 — — 17,632 642,632 
2020625,000 1,500,000 1,000,011 11,019 3,136,030 
Linda J. Bridges (3)2022413,846 200,000 215,000 15,632 844,478 
Executive Vice President and
Chief Financial Officer
Lawrence J. Thuillier2022300,692 150,000 118,250 15,353 584,295 
Chief Accounting Officer2021270,000 150,000 — 14,849 434,849 
2020269,923 — 135,004 9,751 414,678 
Kurston P. McMurray2022495,192 250,000 322,500 3,863 1,071,555 
Executive Vice President and2021375,000 600,000 — 9,210 984,210 
General Counsel and Secretary2020374,039 500,000 100,012 8,857 982,908 
John A. Ciolek2022500,000 250,000 322,500 12,374 1,084,874 
Executive Vice President,2021500,000 — — 15,390 515,390 
Strategic Initiatives2020140,385 — 501,250 119 641,754 
Robert W. Karlovich III (4)2022276,923 — 322,500 6,907 606,330 
Executive Vice President and2021500,000 600,000 — 12,759 1,112,759 
Chief Financial Officer2020500,000 500,000 100,012 6,900 1,106,912 
(1)    The fair values of the restricted units shown in the table above were calculated in accordance with FASB Accounting Standards Codification (“ASC”) Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.
(2)    The amounts in this column include matching contributions to our 401(k) plan and taxable group term life insurance.
(3)     Ms. Bridges became Executive Vice President and Chief Financial Officer effective September 30, 2021, and thus was not a named executive officer prior to fiscal year 2022.
(4)    Mr. Karlovich resigned as Executive Vice President and Chief Financial Officer effective September 30, 2021.

Employment Agreement with Mr. McMurray

Mr. McMurray is party to an employment agreement with the Partnership, dated March 10, 2017. The agreement has a term of five years from the effective date, subject to automatic renewals for one-year periods thereafter unless either party provides 60 days’ notice of non-renewal of the term. The agreement was renewed by its terms as of March 10, 2022. The agreement provides that Mr. McMurray will receive a base salary of no less than $250,000 per year and will be eligible to receive an annual bonus with respect to each fiscal year of the Partnership at a target of 100% of his base salary. Mr. McMurray is also entitled to receive annual awards of unvested units under the Partnership’s LTIP.

In the event that Mr. McMurray’s employment is terminated by the Partnership without “cause” (as defined in his agreement), provided that he executes a general release of claims, Mr. McMurray is entitled to receive (i) continued payment of his base salary for 12 months following the termination, (ii) the guaranteed unit awards that would have been paid or granted to Mr. McMurray had Mr. McMurray remained employed for an additional three years following his termination, and (iii) his target annual bonus for the performance year in which his termination occurs. Mr. McMurray would also be entitled to receive
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the severance benefits described in the foregoing sentence in the event that he voluntarily resigns due to a “constructive discharge,” which circumstances would include (1) a reduction of Mr. McMurray’s annual base salary below $250,000 (other than an across-the-board, pro rata reduction of no more than 10% applicable to all similarly situated executive officers of the Partnership) or the Partnership’s failure to provide Mr. McMurray’s elements of compensation, (2) the removal of Mr. McMurray from the position of Executive Vice President and General Counsel and Secretary without Mr. McMurray’s written consent, (3) any action by the Partnership that results in significant diminution of Mr. McMurray’s authority, power or responsibilities, or (4) the Partnership’s relocation of its principal place of business in Oklahoma to a location more than 50 miles from its current location. Mr. McMurray is subject to non-disclosure and intellectual property rights assignment obligations, and an obligation not to solicit customers, employees or consultants lasting during his employment and for a period of 12 months thereafter.

Restricted Unit Awards

During fiscal year 2022, the compensation committee granted Service Awards to the named executive officers.

2022 Grants of Plan Based Awards

The following table summarizes the number of restricted Service Award units granted to our named executive officers, and their grant date fair values:
NameGrant DateTotal Number of Service Award 
Units (#)
Grant Date Fair Value of
Service Award Units
($)(1)
H. Michael KrimbillMay 5, 2021250,000 537,500 
Linda J. BridgesMay 5, 2021100,000 215,000 
Lawrence J. ThuillierMay 5, 202155,000 118,250 
Kurston P. McMurrayMay 5, 2021150,000 322,500 
John A. CiolekMay 5, 2021150,000 322,500 
Robert W. Karlovich IIIMay 5, 2021150,000 322,500 
(1)    The fair values of the restricted Service Award units shown in the table above were calculated in accordance with ASC Topic 718, Stock Compensation, and does not represent the amount actually realized by the named executive officer at vesting, which may be more or less than the amount reported in the table above. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.

The 2022 Service Awards vest and settle in common units. During fiscal year 2022, the compensation committee granted Service Awards to the named executive officers for which units vest in substantially equal installments on February 10, 2022, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service of the recipients through each such vesting date.

Outstanding Equity Awards at March 31, 2022

The following table summarizes the number of unvested Service Awards outstanding and their fair values at March 31, 2022:
Number of Service Award Units
that Have Not Yet Vested
Market Value of Service Award Units
that Have Not Yet Vested
Name(#)(1)($)(2)
H. Michael Krimbill187,500 416,250 
Linda J. Bridges75,000 166,500 
Lawrence J. Thuillier41,250 91,575 
Kurston P. McMurray112,500 249,750 
John A. Ciolek112,500 249,750 
Robert W. Karlovich III (3)— — 
(1)    Reflects Service Awards that have not vested and are held by each named executive officer. The outstanding Service Awards units vest in substantially equal installments on November 14, 2022, February 13, 2023 and November 15, 2023.
(2)    Calculated based on the closing market price of our common units at March 31, 2022 of $2.22. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.
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(3)    Mr. Karlovich resigned effective September 30, 2021 resulting in the forfeiture of his Service Awards. As a result, Mr. Karlovich did not have any outstanding equity awards as of March 31, 2022.

2022 Units Vested

During fiscal year 2022, certain of the restricted Service Awards vested. The following table summarizes the value of the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates.
NameNumber of Service Award Units
Acquired on Vesting
(#)
Value Realized on Vesting
($)
H. Michael Krimbill (1)137,500 379,500 
Linda J. Bridges (2)31,250 63,250 
Lawrence J. Thuillier (3)18,750 25,300 
Kurston P. McMurray (4)47,500 43,925 
John A. Ciolek (5)50,000 63,250 
Robert W. Karlovich III (6)— — 
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards onNote 4February 10, 2022.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022.
(6)    Mr. Karlovich forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing common units. The following table summarizes the number of common units issued and the number of common units withheld for taxes:
NameNumber of Units
Issued
Number of Units
Withheld
Total
H. Michael Krimbill137,500 — 137,500 
Linda J. Bridges16,753 14,497 31,250 
Lawrence J. Thuillier10,489 8,261 18,750 
Kurston P. McMurray25,489 22,011 47,500 
John A. Ciolek50,000 — 50,000 

Potential Payments Upon Termination or Change in Control

We do not provide any severance or change of control benefits to our named executive officers,other than Mr. McMurray, who is entitled to receive severance benefits for certain types of terminations (as described in more detail above under the heading, “Employment Agreement with Mr. McMurray”). In the event that Mr. McMurray’s employment had been terminated as of March 31, 2022 by the Partnership without “cause” or due to a “constructive discharge,” Mr. McMurray would have been entitled to receive the following amounts:
Cash SeveranceValue of Guaranteed Unit AwardsTarget Annual BonusTotal
$500,000 $249,750 $500,000 $1,249,750 

The board of directors has the option to accelerate the vesting of the Service Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of Service Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the “Outstanding Equity Awards at March 31, 2022” table above (in the “Market Value of Service Award Units that Have Not Yet Vested” column).

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Pay Ratio Disclosure

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information regarding the ratio of the annual total compensation of our Chief Executive Officer, Mr. Krimbill, to the median of the annual total compensation of our employees for our last fiscal year.

For the year ended March 31, 2022:

The median of the annual total compensation of all employees (other than the Chief Executive Officer) was $88,063; and
The annual total compensation of Mr. Krimbill, as reported in the Summary Compensation Table above, was $1,178,219.

Based on the information for the year ended March 31, 2022, the ratio of the annual total compensation of our Chief Executive Officer to the annual total compensation of our median employee was approximately 13 to 1.

To determine our median employee, we identified each individual employed by us on January 1, 2022, our determination date. As of that date, we had 876 employees located in two countries. We identified the median employee by examining only base pay plus overtime for the period from January 1, 2021 through December 31, 2021. We included all employees, with the exception of four employees that work in Canada, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions or adjustments to any base pay plus overtime amounts. After identifying the median employee, we calculated the annual total compensation for the median employee using the same methodology we use to calculate total annual compensation for our named executive officers, as set forth in the Summary Compensation Table above.

This pay ratio is a reasonable estimate calculated in a manner consistent with SEC rules based on our payroll and employment records and the methodology described above. The SEC rules for identifying the median employee and calculating the pay ratio based on that employee’s annual total compensation allow companies to adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices. As such, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

Hedging of Partnership Common Units

Our Supplemental Trading Policy prohibits directors, named executive offices and other designated employees from engaging in hedging activities with respect to our common units.

Director Compensation

Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following cash compensation for his board service:

an annual retainer of $80,000;
an annual retainer of $20,000 for the chairman of the audit committee;
an annual retainer of $15,000 for the chairman of the compensation committee;
an annual retainer of $14,000 for each member of the audit committee other than the chairman; and
an annual retainer of $10,000 for each member of the compensation committee other than the chairman.

In addition, each director who is not an officer or employee of our general partner or its affiliates has been granted awards of restricted units. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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The following table summarizes the compensation earned during fiscal year 2022 by each director who is not an officer or employee of our general partner or its affiliates:
NameFees Earned or
Paid in Cash
($)
Restricted Unit
Awards
($)(1)
Total
($)
Shawn W. Coady80,000 107,500 187,500 
James M. Collingsworth104,000 107,500 211,500 
Stephen L. Cropper109,000 107,500 216,500 
Bryan K. Guderian104,000 107,500 211,500 
Derek S. Reiners100,000 107,500 207,500 
(1)    The amounts reflected in this column represent the grant date fair value of each director’s May 5, 2021 award of 50,000 restricted units, which were calculated in accordance with ASC Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report. See table below for discussion of the vesting of these grants.

Long-Term Equity Incentive Awards

The following table summarizes Service Award units activity during fiscal year 2022 with respect to each director who is not an officer or employee of our general partner or its affiliates:
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits Vested (1)March 31, 2022 (2)
Shawn W. Coady4,000 50,000 (16,500)37,500 
James M. Collingsworth4,000 50,000 (16,500)37,500 
Stephen L. Cropper4,000 50,000 (16,500)37,500 
Bryan K. Guderian4,000 50,000 (16,500)37,500 
Derek S. Reiners4,000 50,000 (16,500)37,500 
(1)    4,000 Service Awards vested on November 12, 2021 and 12,500 Service Awards vested on February 10, 2022.
(2)    12,500 Service Awards will vest on November 14, 2022, 12,500 Service Awards will vest on February 13, 2023 and 12,500 Service Awards will vest on November 15, 2023, subject to the continued service of the recipients through each such vesting date.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table summarizes the beneficial ownership, as of June 1, 2022, of our common units by:

each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;
each director of our general partner;
each named executive officer of our general partner; and
all directors and executive officers of our general partner as a group.
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Beneficial OwnersCommon Units
Beneficially
Owned
Percentage of
Common Units
Beneficially
Owned (1)
5% or greater unitholders (other than officers and directors):  
Invesco Ltd. (2)19,717,009 15.09 %
EIG Neptune Equity Aggregator, L.P. (3)16,734,375 11.35 %
Directors and named executive officers:  
Linda J. Bridges (4)62,165 *
John A. Ciolek (5)194,764 *
Shawn W. Coady (6)2,614,695 2.00 %
James M. Collingsworth (7)352,370 *
Stephen L. Cropper (8)87,500 *
Bryan K. Guderian85,000 *
H. Michael Krimbill (9)4,127,518 3.16 %
Kurston P. McMurray (10)84,231 *
John T. Raymond50,000 *
Derek S. Reiners38,500 *
Lawrence J. Thuillier (11)60,319 *
Randall S. Wade— *
All directors and executive officers as a group (12 persons) (12)7,757,062 5.94 %
* Less than 1.0%
(1)    Based on 130,695,970 common units outstanding at June 1, 2022.
(2)    The mailing address for Invesco Ltd. is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. Invesco Ltd. reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to Invesco Ltd. is based upon its Schedule 13G/A filed with the SEC on February 10, 2022.
(3)    The mailing address for EIG Neptune Equity Aggregator, L.P. (“EIG Neptune”) is 600 New Hampshire Ave NW, Suite 1200, Washington, DC 20037. EIG Neptune reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to EIG Neptune is based upon its Schedule 13D/A filed with the SEC on September 4, 2020. The common units beneficially owned relate to warrants that were exercisable on July 2, 2020. For purposes of calculating ownership percentages, the units underlying the warrants are only deemed outstanding for purposes of calculating EIG Neptune’s percentage.
(4)    Does not include 75,000 unvested units, of which 25,000 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(5)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(6)    Dr. Coady owns 134,804 of these common units. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole member. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 of these common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 of these common units. Dr. Coady also owns a12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(7)    Mr. Collingsworth owns 340,000 of these common units. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 9,500 of these common units. Cindy Collingsworth owns 870 of these common units.
(8)Mr. Cropper owns 62,500 of these common units. The Donna L. Cropper Revocable Living Trust, of which Mr. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.
(9)    Mr. Krimbill owns 2,241,115 of these common units, which does not include 187,500 unvested units, of which 62,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. All of the unvested units noted above were reported on Mr. Krimbill’s Form 4. Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP also owns 488,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to
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have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Krimbill Enterprises LP, II also owns 130,000 of these common units. Krimbill Enterprises LP, II is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests.
(10)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. Mr. McMurray owns a 0.25% interest in our general partner through MCM Investments, LLC, of which he owns 100% of the membership interests.
(11)    Does not include 41,250 unvested units, of which 13,750 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(12)    The directors and executive officers of our general partner also collectively own a 29.69% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2022.
Number of Securities to be
Issued upon Exercise of
Outstanding Options,
Warrants and Rights
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
Number of Securities
Remaining Available for
Future Issuances Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
Plan Category (a)(b)(c)
Equity Compensation Plans Approved by Security Holders— — — 
Equity Compensation Plans Not Approved by Security Holders (1)2,188,800 — — 
Total2,188,800 — — 
(1)    Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011, which did not require the approval of our unitholders. Prior to the expiration of the LTIP on May 10, 2021, we granted approximately 3.3 million common units as Service Awards, which will vest in our 2023 and 2024 fiscal years. Due to the LTIP expiring, we have no common units available for grant and any current unvested Service Awards that are forfeited or canceled will not be available for future grants.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 44,208,446 common units, representing an aggregate 33.83% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distribution rights (“IDRs”). As of March 31, 2022, we owned 8.69% of our general partner.

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount of these expenses. In addition, our general partner owns the 0.1% general partner interest and all of the IDRs. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

The following table summarizes the distributions and payments to be made by us to our directors, executive officers, and greater than 5% unitholders and our general partner in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.
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Operation Stage
Distributions of available cash to our directors, executive officers, and greater than 5% unitholders and our general partnerWe generally make cash distributions 99.9% to our unitholders pro rata, including our directors, executive officers, and greater than 5% unitholders as the holders of an aggregate 44,208,446 common units, and 0.1% to our general partner. In addition, when distributions exceed the minimum quarterly distribution and other higher target distributions levels, our general partner is entitled to increasing percentages of the distributions, up to 48.1% of the distributions above the highest target distribution level.
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
As described in Note 7 to our consolidated financial statements included in this Annual Report, the indenture to the 2026 Senior Secured Notes restricts us from paying 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. In addition, quarterly distributions on the preferred units must be fully paid for all preceding fiscal quarters before we are permitted to declare or pay any distributions on our common units.
Payments to our general partner and its affiliatesOur general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. As the sole purpose of the general partner is to act as our general partner, substantially all of the expenses of our general partner are incurred on our behalf and reimbursed by us or our subsidiaries. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partnerIf our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
LiquidationUpon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Transactions with Related Persons

We purchase goods and services from certain entities that are partially owned by our named executive officers. The following table summarizes these transactions from April 1, 2021 to March 31, 2022:
EntityNature of PurchasesAmount PurchasedOwnership Interest in Entity
(in thousands)
H. Michael Krimbill
KAIR2014 LLC (“KAIR2014”)Aircraft$670 50 %

In connection with the purchase of our 50% interest in an aircraft company, KAIR2014, we executed a joint and several guarantee for the benefit of the lender for KAIR2014’s outstanding loan. The other owner of KAIR2014, our Chief Executive Officer, H. Michael Krimbill, 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 March 31, 2022, the outstanding balance of the loan is approximately $2.5 million. Payments are made monthly, reducing the outstanding balance, 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 March 31, 2022, no accrual has been recorded related to this guarantee.
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Travis Krimbill, an employee of the Partnership, is the son of H. Michael Krimbill, who is a named executive officer of the Partnership and a member of the board of directors. Travis Krimbill does not report to H. Michael Krimbill and his compensation is determined by the Chief Financial Officer. During the year ended March 31, 2022, Travis Krimbill received total compensation of approximately $0.2 million.

Registration Rights Agreement

We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registration rights parties”) pursuant to which we agreed to register for resale under the Securities Act of 1933, as amended (“Securities Act”) common units owned by the parties to the Registration Rights Agreement. In connection with our IPO, we granted registration rights to the NGL Energy GP Investor Group, and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if an exemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject to limitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following:

Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that they continue to own more than 4% of our common units, require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file a total of nine registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million.
Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.
Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies for the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers will make all reasonable efforts to cancel or annul the transaction.

The Code of Business Conduct and Ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to:

whether there is an appropriate business justification for the transaction;
the benefits that accrue to the Partnership as a result of the transaction;
the terms available to unrelated third parties entering into similar transactions;
the impact of the transaction on a director’s independence (in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer);
the availability of other sources for comparable products or services;
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whether it is a single transaction or a series of ongoing, related transactions; and
whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

Director Independence

The NYSE does not require a listed publicly traded limited partnership like NGL to have a majority of independent directors on the board of directors of its general partner. For a discussion of the independence of the board of directors of our general partner, see Part III, Item 10–“Directors, Executive Officers and Corporate Governance–Board of Directors of our General Partner.”

Item 14.    Principal Accountant Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Grant Thornton LLP to audit our annual consolidated financial statements and for other services for the periods indicated:
March 31,
20222021
(in thousands)
Audit fees (1)$1,882 $2,149 
Audit-related fees (2)— 
Tax fees— — 
All other fees— — 
Total$1,882 $2,156 
(1)    Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.
(2)    Includes fees in fiscal year 2021 for review services for one of our subsidiaries.

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.

111


PART IV
Item 15.    Exhibit and Financial Statement Schedules

(a)    The following documents are filed as part of this Annual Report:
1.    Financial Statements. See the accompanying Index to Financial Statements.
2.    Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.
3.    Exhibits.
Exhibit NumberDescription
2.1
2.2
2.3
2.4
2.5
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
112


Exhibit NumberDescription
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
113


Exhibit NumberDescription
4.20
4.21
4.22*
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32*
4.33
4.34
4.35
4.36
4.37
4.38
114


Exhibit NumberDescription
4.39
4.40*
4.41
4.42
4.43*
4.44
4.45
4.46
4.47*
10.1
10.2
10.3*
10.4*
10.5
10.6+
10.7+
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
115


Exhibit NumberDescription
10.16
21.1*
22.1*
23.1*
31.1*
31.2*
32.1*
32.2*
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
104Cover 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) Consolidated Balance Sheets at March 31, 2022 and 2021, (ii) Consolidated Statements of Operations for the years ended March 31, 2022, 2021, and 2020, (iii) Consolidated Statements of Comprehensive Loss for the years ended March 31, 2022, 2021, and 2020, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2022, 2021, and 2020, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2022, 2021, and 2020, and (vi) Notes to Consolidated Financial Statements.
+    Management contracts or compensatory plans or arrangements.

Item 16.    Form 10-K Summary

None.
116


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on June 6, 2022.
NGL ENERGY PARTNERS LP
By:NGL Energy Holdings LLC, its general partner
By:/s/ H. Michael Krimbill
H. Michael Krimbill
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ H. Michael KrimbillChief Executive Officer and DirectorJune 6, 2022
H. Michael Krimbill(Principal Executive Officer)
/s/ Linda J. BridgesChief Financial OfficerJune 6, 2022
Linda J. Bridges(Principal Financial Officer)
/s/ Lawrence J. ThuillierChief Accounting OfficerJune 6, 2022
Lawrence J. Thuillier(Principal Accounting Officer)
/s/ Shawn W. CoadyDirectorJune 6, 2022
Shawn W. Coady
/s/ James M. CollingsworthDirectorJune 6, 2022
James M. Collingsworth
/s/ Stephen L. CropperDirectorJune 6, 2022
Stephen L. Cropper
/s/ Bryan K. GuderianDirectorJune 6, 2022
Bryan K. Guderian
/s/ John T. RaymondDirectorJune 6, 2022
John T. Raymond
/s/ Derek S. ReinersDirectorJune 6, 2022
Derek S. Reiners
/s/ Randall S. WadeDirectorJune 6, 2022
Randall S. Wade
117


INDEX TO FINANCIAL STATEMENTS
NGL Energy Partners LP
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
F-2
Consolidated Balance Sheets at March 31, 2022 and 2021
F-4
Consolidated Statements of Operations for the years ended March 31, 2022, 2021, and 2020
F-5
Consolidated Statements of Comprehensive Loss for the years ended March 31, 2022, 2021, and 2020
F-6
Consolidated Statements of Changes in Equity for the years ended March 31, 2022, 2021, and 2020
F-7
Consolidated Statements of Cash Flows for the years ended March 31, 2022, 2021, and 2020
F-8
Notes to Consolidated Financial Statements
F-9

F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2022 and 2021, the related consolidated statements of operations, comprehensive loss, changes in equity, and cash flows for each of the three years in the period ended March 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of March 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated June 6, 2022 expressed an unqualified opinion.

Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill Impairment Assessment
As described further in Note 5 to the consolidated financial statements, the Partnership’s consolidated goodwill balance was $744.4 million as of March 31, 2022. Management evaluates goodwill for impairment on January 1 of each year, or more frequently to the extent events or conditions indicate a risk of possible impairment. Management performed a quantitative impairment assessment for the Crude Oil Logistics reporting unit to test goodwill for impairment as of January 1, 2022. As a result of the assessment performed for the reporting unit, and as described further in Note 5 to the consolidated financial statements, the Partnership concluded the fair value of the Crude Oil Logistics reporting unit exceeded its carrying value and no goodwill impairment was recorded. We identified the goodwill impairment assessment as a critical audit matter.

The principal considerations for our determination that the goodwill impairment assessment was a critical audit matter are that there was a high estimation uncertainty due to significant judgments with respect to assumptions used to estimate the future revenues and cash flows, including revenue growth rates, operating expenses and cash outflows necessary to support the cash flows, weighted average costs of capital and future market conditions as well as the valuation methodologies applied by the Partnership. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to management’s forecasted future revenues and cash flows. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
F-2



Our audit procedures related to the goodwill impairment assessment included the following, among others. We tested the effectiveness of controls relating to management’s goodwill impairment tests, including controls over the determination of the fair value of the reporting unit. In addition to testing the effectiveness of controls, we also performed the following:

Utilized a valuation specialist to evaluate:
The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing an independent calculation,
The appropriateness of the discount rate by recalculating the weighted average costs of capital and evaluating future market conditions, and
Other significant assumptions, including the terminal growth rate.
Tested the reasonableness of management’s process for determining the fair value of the reporting unit, including the revenue growth rate, forecasted costs and operating margins by comparing such items to the industry projections and conditions found in industry reports as well as historical operating results of the reporting unit and by assessing the likelihood or capability of the reporting unit to undertake activities or initiatives underpinning significant drivers of growth in the forecasted period.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2010.

Tulsa, Oklahoma
June 6, 2022

F-3


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Balance Sheets
(in Thousands, except unit amounts)
March 31,
20222021
ASSETS
CURRENT ASSETS:
Cash and cash equivalents$3,822 $4,829 
Accounts receivable-trade, net of allowance for expected credit losses of $2,626 and $2,192, respectively1,123,163 725,943 
Accounts receivable-affiliates8,591 9,435 
Inventories251,277 158,467 
Prepaid expenses and other current assets159,486 109,164 
Total current assets1,546,339 1,007,838 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $887,006 and $776,279, respectively2,462,390 2,706,853 
GOODWILL744,439 744,439 
INTANGIBLE ASSETS, net of accumulated amortization of $507,285 and $517,518, respectively1,135,354 1,262,613 
INVESTMENTS IN UNCONSOLIDATED ENTITIES21,897 22,719 
OPERATING LEASE RIGHT-OF-USE ASSETS114,124 152,146 
OTHER NONCURRENT ASSETS45,802 50,733 
Total assets$6,070,345 $5,947,341 
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade$1,084,837 $679,868 
Accounts payable-affiliates73 119 
Accrued expenses and other payables140,719 170,400 
Advance payments received from customers7,934 11,163 
Current maturities of long-term debt2,378 2,183 
Operating lease obligations41,261 47,070 
Total current liabilities1,277,202 910,803 
LONG-TERM DEBT, net of debt issuance costs of $42,988 and $55,555, respectively, and current maturities3,350,463 3,319,030 
OPERATING LEASE OBLIGATIONS72,784 103,637 
OTHER NONCURRENT LIABILITIES104,346 114,615 
COMMITMENTS AND CONTINGENCIES (NOTE 8)00
CLASS D 9.00% PREFERRED UNITS, 600,000 and 600,000 preferred units issued and outstanding, respectively551,097 551,097 
EQUITY:
General partner, representing a 0.1% interest, 130,827 and 129,724 notional units, respectively(52,478)(52,189)
Limited partners, representing a 99.9% interest, 130,695,970 and 129,593,939 common units issued and outstanding, respectively401,486 582,784 
Class B preferred limited partners, 12,585,642 and 12,585,642 preferred units issued and outstanding, respectively305,468 305,468 
Class C preferred limited partners, 1,800,000 and 1,800,000 preferred units issued and outstanding, respectively42,891 42,891 
Accumulated other comprehensive loss(308)(266)
Noncontrolling interests17,394 69,471 
Total equity714,453 948,159 
Total liabilities and equity$6,070,345 $5,947,341 
The accompanying notes are an integral part of these consolidated financial statements.
F-4


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Operations
(in Thousands, except unit and per unit amounts)
Year Ended March 31,
202220212020
REVENUES:
Water Solutions$544,866 $370,986 $422,059 
Crude Oil Logistics2,505,496 1,721,636 2,549,767 
Liquids Logistics4,897,553 3,133,146 4,611,136 
Corporate and Other— 1,255 1,038 
Total Revenues7,947,915 5,227,023 7,584,000 
COST OF SALES:
Water Solutions33,980 9,622 (33,870)
Crude Oil Logistics2,352,932 1,515,993 2,293,953 
Liquids Logistics4,752,400 2,966,391 4,342,526 
Corporate and Other— 1,816 1,774 
Total Cost of Sales7,139,312 4,493,822 6,604,383 
OPERATING COSTS AND EXPENSES:
Operating285,535 254,562 332,993 
General and administrative63,546 70,468 113,664 
Depreciation and amortization288,720 317,227 265,312 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Revaluation of liabilities(6,495)6,261 9,194 
Operating Income (Loss)83,043 (390,753)(3,332)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities1,400 1,938 1,291 
Interest expense(271,640)(198,799)(181,184)
Gain (loss) on early extinguishment of liabilities, net1,813 (16,692)1,341 
Other income (expense), net2,254 (36,503)1,684 
Loss From Continuing Operations Before Income Taxes(183,130)(640,809)(180,200)
INCOME TAX (EXPENSE) BENEFIT(971)3,391 (345)
Loss From Continuing Operations(184,101)(637,418)(180,545)
Loss From Discontinued Operations, net of Tax— (1,769)(218,235)
Net Loss(184,101)(639,187)(398,780)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS(655)(632)1,773 
NET LOSS ATTRIBUTABLE TO NGL ENERGY PARTNERS LP$(184,756)$(639,819)$(397,007)
NET LOSS FROM CONTINUING OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(730,683)$(367,246)
NET LOSS FROM DISCONTINUED OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$— $(1,767)$(218,017)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(732,450)$(585,263)
BASIC LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
DILUTED LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
 The accompanying notes are an integral part of these consolidated financial statements.
F-5


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
(in Thousands)
Year Ended March 31,
202220212020
Net loss$(184,101)$(639,187)$(398,780)
Other comprehensive (loss) income(42)119 (130)
Comprehensive loss$(184,143)$(639,068)$(398,910)

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

F-6


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended March 31, 2022, 2021, and 2020
(in Thousands, except unit amounts)
Limited Partners
PreferredCommon
General
Partner
UnitsAmount
Units
AmountAccumulated Other Comprehensive Income (Loss)Noncontrolling
Interests
Total
Equity
BALANCES AT MARCH 31, 2019$(50,603)8,400,000 $202,731 124,508,497 $2,067,197 $(255)$58,748 $2,277,818 
Distributions to general and common unit partners and preferred unitholders (Note 9)(342)— — — (258,020)— — (258,362)
Distributions to noncontrolling interest owners— — — — — — (1,145)(1,145)
Issuance of Class B preferred units, net of offering costs (Note 9)— 4,185,642 102,737 — — — — 102,737 
Issuance of Class C preferred units, net of offering costs (Note 9)— 1,800,000 42,891 — — — — 42,891 
Issuance of warrants, net of offering costs (Note 9)— — — — 52,742 — — 52,742 
Warrants exercised (Note 9)— — — 1,458,371 15 — — 15 
Accretion of beneficial conversion feature of 10.75% Class A convertible preferred units (Note 9)— — — — (36,517)— — (36,517)
10.75% Class A convertible preferred units redemption - amount paid in excess of carrying value (Note 9)— — — — (78,797)— — (78,797)
Equity issued pursuant to incentive compensation plan33 — — 2,938,481 32,931 — — 32,964 
Common unit repurchases and cancellations— — — (133,634)(1,644)— — (1,644)
Mesquite Disposals Unlimited, LLC ("Mesquite") acquisition— — — — — — 17,124 17,124 
Investment in NGL Energy Holdings LLC (Note 12)— — — — (15,226)— — (15,226)
Net loss(478)— — — (396,529)— (1,773)(398,780)
Other comprehensive loss— — — — — (130)— (130)
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 (Note 9)(65)— — — (147,715)— — (147,780)
Distributions to noncontrolling interest owners— — — — — — (4,115)(4,115)
Common unit repurchases and cancellations— — — (70,226)(182)— — (182)
Equity issued pursuant to incentive compensation plan— — — 892,450 4,727 — — 4,727 
Net (loss) income(733)— — — (639,086)— 632 (639,187)
Other comprehensive income— — — — — 119 — 119 
Cumulative effect adjustment for adoption of ASU 2016-13 (Note 16)(1)— — — (1,112)— — (1,113)
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— — — — — — (1,635)(1,635)
Sawtooth joint venture disposition (Note 17)— — — — — — (51,097)(51,097)
Common unit repurchases and cancellations (Note 9)— — — (44,769)(90)— — (90)
Equity issued pursuant to incentive compensation plan (Note 9)— — — 1,146,800 3,259 — — 3,259 
Net (loss) income(289)— — — (184,467)— 655 (184,101)
Other comprehensive loss— — — — — (42)— (42)
BALANCES AT MARCH 31, 2022$(52,478)14,385,642 $348,359 130,695,970 $401,486 $(308)$17,394 $714,453 
The accompanying notes are an integral part of these consolidated financial statements.
F-7


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in Thousands)
Year Ended March 31,
202220212020
OPERATING ACTIVITIES:
Net loss$(184,101)$(639,187)$(398,780)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations, net of tax— 1,769 218,235 
Depreciation and amortization, including amortization of debt issuance costs306,208 331,200 276,848 
(Gain) loss on early extinguishment or revaluation of liabilities, net(8,308)22,953 7,853 
Non-cash equity-based compensation expense(1,052)6,727 26,510 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Change in provision for expected credit losses929 5,988 1,002 
Net adjustments to fair value of commodity derivatives116,556 83,578 (85,941)
Equity in earnings of unconsolidated entities(1,400)(1,938)(1,291)
Distributions of earnings from unconsolidated entities2,205 3,364 — 
Lower of cost or net realizable value adjustments14,761 3,898 33,973 
Other2,310 1,513 2,541 
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates(397,607)(162,031)436,349 
Inventories(119,806)(92,731)29,779 
Other current and noncurrent assets40,158 92,555 14,081 
Accounts payable-trade and affiliates405,420 207,505 (375,257)
Other current and noncurrent liabilities(64,681)(34,836)(65,262)
Net cash provided by operating activities-continuing operations205,846 305,763 382,426 
Net cash (used in) provided by operating activities-discontinued operations— (1,769)81,629 
Net cash provided by operating activities205,846 303,994 464,055 
INVESTING ACTIVITIES:
Capital expenditures(142,359)(186,801)(555,713)
Acquisitions, net of cash acquired— 901 (1,268,474)
Net settlements of commodity derivatives(152,055)(80,372)86,702 
Proceeds from sales of assets18,500 45,742 17,621 
Proceeds from divestitures of businesses and investments, net63,489 — — 
Investments in unconsolidated entities(350)(963)(21,218)
Distributions of capital from unconsolidated entities367 — 440 
Repayments on loan for natural gas liquids facility— — 3,022 
Net cash used in investing activities-continuing operations(212,408)(221,493)(1,737,620)
Net cash provided by investing activities-discontinued operations— — 298,864 
Net cash used in investing activities(212,408)(221,493)(1,438,756)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities1,815,000 1,261,000 4,074,000 
Payments on revolving credit facilities(1,703,000)(2,727,000)(3,775,000)
Issuance of senior secured and unsecured notes and term credit agreement— 2,300,000 700,000 
Repayment of term credit agreements— (555,562)— 
Repayment and repurchase of senior unsecured notes(83,167)(115,796)(454)
Proceeds from borrowings on other long-term debt— 50,000 — 
Payments on other long-term debt(7,390)(5,590)(653)
Debt issuance costs(12,932)(65,566)(14,950)
Distributions to general and common unit partners and preferred unitholders— (142,128)(244,400)
Distributions to noncontrolling interest owners(1,635)(4,115)(1,145)
Proceeds from sale of preferred units, net of offering costs— — 622,391 
Payments for redemption of preferred units— — (265,128)
Common unit repurchases and cancellations(90)(182)(1,644)
Payments to settle contingent consideration liabilities(1,231)(95,437)(98,958)
Investment in NGL Energy Holdings LLC— — (15,226)
Net cash provided by (used in) financing activities5,555 (100,376)978,833 
Net (decrease) increase in cash and cash equivalents(1,007)(17,875)4,132 
Cash and cash equivalents, beginning of period4,829 22,704 18,572 
Cash and cash equivalents, end of period$3,822 $4,829 $22,704 
Supplemental cash flow information:
Cash interest paid$254,814 $168,642 $155,445 
Income taxes paid (net of income tax refunds)$2,480 $2,586 $4,931 
Supplemental non-cash investing and financing activities:
Distributions declared but not paid to preferred unitholders$— $13,814 $18,687 
Accrued capital expenditures$14,558 $21,824 $88,917 
The accompanying notes are an integral part of these consolidated financial statements.
F-8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 1—Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At March 31, 2022, our operations included 3 segments:

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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 owned and leased 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 owned terminals, third-party storage and terminal facilities, 9 common carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and expect to commence operations on our propane pipeline in Michigan in June 2022.

Note 2—Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The accompanying 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 consolidated financial statements.

Use of Estimates

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

Critical accounting estimates we make in the preparation of our consolidated financial statements include, among others, determining the impairment of goodwill and long-lived assets, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the fair value of derivative instruments, estimating certain revenues, the fair value of asset retirement obligations, the fair value of assets and liabilities acquired in acquisitions, the recoverability of inventories, the collectibility of accounts and notes receivable and accruals for environmental matters. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Level 1: Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level 2: Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and forward commodity contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
Level 3: Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for normal purchase and normal sale transactions that are expected to result in physical delivery. For these transactions, 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.

We have not designated any financial instruments as hedges for accounting purposes. 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements and are reported within cost of sales on the consolidated statements of operations, along with related settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Cost of Sales

We include all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory, prior to delivery to our customers, in cost of sales. Cost of sales excludes depreciation of our property, plant and equipment.

Depreciation and Amortization

Depreciation and amortization in our consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

to interest expense and certain contract-based intangible assets, for which the amortization is recorded to either cost of sales or operating expense.

Income Taxes

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

We have certain taxable corporate subsidiaries in the United States and Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2018 to 2021 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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

We have a deferred tax liability of $43.5 million and $45.8 million at March 31, 2022 and 2021, respectively, as a result of acquiring corporations in connection with certain of our acquisitions, which is included within other noncurrent liabilities in our 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 year ended March 31, 2022 was $1.2 million with an effective tax rate of 11.3%. The deferred tax benefit recorded during the year ended March 31, 2021 was $4.7 million with an effective tax rate of 39.7%.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no uncertain tax positions that required recognition in our consolidated financial statements at March 31, 2022 or 2021.

Cash and Cash Equivalents

Management considers all highly liquid investments with a maturity of three months or less, when purchased, to be cash equivalents. We place our cash and cash equivalents with financial institutions that are still within this measurement period,insured by the Federal Deposit Insurance Corporation; however, we maintain deposits in banks which exceed the amount of deposit insurance available. Management routinely assesses the financial condition of the institutions and believes that any possible credit loss would be minimal.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. See Note 16 for a result,further discussion of our allowance for expected credit losses.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the acquisition date fair valuesextent a netting agreement is in place and we have recordedintend to settle on a net basis.

CITGO Petroleum Corporation accounted for 12.8% of our consolidated revenues for the year ended March 31, 2022. The majority of the revenue for this customer pertains to our Crude Oil Logistics segment activities, and sales to this customer
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

occur mainly out of our crude oil terminal in Cushing, Oklahoma. We did not have any customers that represented over 10% of consolidated revenues for the years ended March 31, 2021 and 2020.

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:
March 31,
20222021
(in thousands)
Crude oil$135,485 $64,916 
Propane43,971 45,521 
Butane33,144 19,189 
Biodiesel20,474 16,169 
Diesel3,504 2,252 
Ethanol3,503 3,056 
Other11,196 7,364 
Total$251,277 $158,467 

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. Under the equity method, we do not report the individual assets acquired and liabilities assumedof these entities on our consolidated balance sheets; instead, our ownership interests are subjectreported within investments in unconsolidated entities on our consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the net assets of the investee. We consider distributions received from unconsolidated entities which do not exceed cumulative equity in earnings subsequent to change.the date of investment to be a return on investment and are classified as operating activities in our consolidated statements of cash flows. We consider distributions received from unconsolidated entities in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in our consolidated statements of cash flows.

At March 31, 2022, cumulative equity earnings and cumulative distributions of our unconsolidated entities since they were acquired were $6.5 million and $9.4 million, respectively.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Our investments in unconsolidated entities consist of the following at the dates indicated:
March 31,
EntitySegmentOwnership Interest20222021
(in thousands)
Water services and land companyWater Solutions50%$15,714 $15,832 
Water services and land companyWater Solutions10%2,863 3,254 
Water services and land companyWater Solutions50%2,210 2,284 
Aircraft company (1)Corporate and Other50%538 748 
Water services companyWater Solutions50%409 424 
Natural gas liquids terminal companyLiquids Logistics50%163 177 
Total$21,897 $22,719 
(1)    This is an investment with a related party. See Note 12 for a further discussion.

Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Linefill (1)$28,065 $28,110 
Minimum shipping fees - pipeline commitments (2)8,899 13,171 
Loan receivable (3)3,147 2,962 
Other5,691 6,490 
Total$45,802 $50,733 
(1)    Represents minimum volumes of product we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At March 31, 2022 and 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). During the three months ended March 31, 2020, we recorded an impairment of $7.7 million primarily due to adjusting the cost basis of pipeline linefill to the market price of propane as of March 31, 2020.
(2)    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 8). As of March 31, 2022, the deficiency credit was $13.2 million, of which $4.3 million is recorded within prepaid expenses and other current assets in our consolidated balance sheet.
(3)    Represents the noncurrent portion of a loan receivable, net of an allowance for an expected credit loss, with a former related party.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Accrued interest$56,104 $56,299 
Derivative liabilities27,108 21,562 
Accrued compensation and benefits18,417 41,456 
Excise and other tax liabilities10,451 10,970 
Product exchange liabilities853 1,188 
Other27,786 38,925 
Total$140,719 $170,400 
Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included within loss on disposal or impairment of
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

assets, net. We compute depreciation expense of our property, plant and equipment using the straight-line method over the estimated useful lives of the assets (see Note 4).

Recent Accounting Pronouncements

In June 2016, the FinancialFor a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our consolidated financial statements included in this Annual Report.

Critical Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Financial Instruments-Credit Losses.” Estimates

The ASU requires a financial asset (or a grouppreparation of financial assets) measured at amortized coststatements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to be presented at the net amount expected to be collected, which would include accounts receivable. The measurementrelevant facts and circumstances of expected credit losses is based on relevant information about past events, including historical experience, current conditions,our operations and reasonable and supportable forecasts that affect the collectibilityuse of estimates made by management. We have identified the reported amount. The ASU is effective for the Partnership beginning April 1, 2020, and requires a modified retrospective method of adoption, although early adoption is permitted. We are currentlyfollowing more critical judgment areas in the processapplication of assessingour accounting policies that are most important to the impactportrayal of this ASUour 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.

Impairment of Goodwill

The goodwill relating to each of our reporting units is tested for impairment annually as well as when an event or change in circumstances indicates an impairment may have occurred. For each reporting unit, we perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying value, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewing several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’s fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, an impairment loss is recognized to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value, limited to the total amount of goodwill for the reporting unit. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. During the years ended March 31, 2021 and 2020, we recorded goodwill impairments of $237.8 million and $250.0 million, respectively. We did not record a goodwill impairment during the year ended March 31, 2022. See Note 5 to our consolidated financial statements included in this Annual Report for a further discussion of our goodwill impairment assessment.

Impairment of Long-Lived Assets

We evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans as well as external factors such as industry and economic trends. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates. If the carrying value is not recoverable, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. See Note 4 and Note 6 to our consolidated financial statements included in this Annual Report for a further discussion of our impairments of long-lived assets.
F-18
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We evaluate our investments in unconsolidated entities for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the fair value of such investment may have experienced a decline to less than its carrying value and the decline is other than temporary.

Depreciation and Amortization Methods and Estimated Useful Lives of Property, Plant and Equipment and Intangible Assets

Depreciation and amortization expense is the systematic write-off of the cost of our property, plant and equipment (net of residual or salvage value, if any) and the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate our property, plant and equipment and amortize the majority of our intangible assets using the straight-line method, which results in our recording depreciation and amortization expense evenly over the estimated life of the individual asset. The estimate of depreciation and amortization expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipment in service or acquire intangible assets, we develop assumptions about the useful economic lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation and amortization expense prospectively and have a material impact on our results of operations. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, changes in expected salvage values or changes in customer attrition rates. See Note 2, Note 4 and Note 6 to our consolidated financial statements included in this Annual Report for a further discussion.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for normal purchase and normal sale transactions that are expected to result in physical delivery. Changes in the fair value are recorded within revenue (for sales contracts) or cost of sales (for purchase contracts) in our consolidated statements of operations. We determine the fair value of our exchange traded derivative financial instruments utilizing publicly available prices, and for non-exchange traded derivative financial instruments, we utilize pricing models for similar instruments including publicly available prices and forward curves generated from a compilation of data gathered from third parties. Actual amounts could vary materially from estimated fair values due to changes in market prices. In addition, changes in the methods or assumptions used to determine the fair value of our derivative financial instruments could have a material effect on our consolidated financial statements. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk to see the impact of a 10% increase in the underlying commodity value and Note 2 and Note 10 to our consolidated financial statements included in this Annual Report for a further discussion of our derivative financial instruments.

Revenue Recognition

Our Water Solutions segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our corresponding performance obligation, and the difference in timing of revenue recognition and billings results in contract assets and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management including volume and forecasted production information. Changes in these assumptions or a contract modification could have a material effect on the amount of variable consideration recognized as revenue. See Note 14 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies.

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 largest asset retirement obligations involve the abandonment or removal of pipelines and saltwater and freshwater disposal wells. We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. Most of these retirement obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. These estimates and assumptions are very subjective and can vary
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over time. Our consolidated balance sheet at March 31, 2022 includes a liability of $29.9 million related to asset retirement obligations, which is reported within other noncurrent liabilities.

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.

Acquisitions

Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. For a business combination, the excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but instead is evaluated for impairment at least annually. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination.

Inventories

Our inventories consist of crude oil, natural gas liquids, diesel, ethanol and biodiesel. 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. At the end of each fiscal year, we also perform a “lower of cost or net realizable value” analysis; if the cost basis of the inventories would not be recoverable based on the net realizable value at the end of the year, we reduce the book value of the inventories to the recoverable amount. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or net realizable value write-down if we expect the net realizable value to recover by our fiscal year end. The net realizable values of these commodities change on a daily basis as supply and demand conditions change. We are unable to control changes in the net realizable value of these commodities and are unable to determine whether write-downs will be required in future periods.

Item 7A.    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, which has since been determined to be an adjusted forward-looking term rate based on the secured overnight financing rate). At March 31, 2022, we had $116.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 4.64%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.1 million, based on borrowings outstanding at March 31, 2022.

In addition, on and after certain dates, distributions for our Class B Preferred Units and Class C Preferred Units will be calculated using the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) 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 alternative rate as determined in the partnership agreement) plus a spread of 7.213%. For our Class C Preferred Units, distributions on and after April 15, 2024 will
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accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) 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 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled. See “Critical Accounting Estimates” above for a discussion of how we determine the fair value of our financial derivative instruments.

The following table summarizes the hypothetical impact on the March 31, 2022 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 (Water Solutions segment)$(4,838)
Crude oil (Crude Oil Logistics segment)$(8,612)
Propane (Liquids Logistics segment)$532 
Butane (Liquids Logistics segment)$(3,026)
Refined Products (Liquids Logistics segment)$(2,598)
Other Products (Liquids Logistics segment)$4,106 

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 try to 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;
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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.

At March 31, 2022, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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Item 8.    Financial Statements and Supplementary Data

Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the report of Grant Thornton LLP, our independent registered public accounting firm, are incorporated by reference into this Item 8.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure 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 the 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 (“SEC”) 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 March 31, 2022. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2022, such disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting

The management of our Delaware limited partnership (the “Partnership”) and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO framework.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2022.

Our internal control over financial reporting as of March 31, 2022 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report, which appears below in this section of the Annual Report.

Changes in Internal Control Over Financial Reporting

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 March 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2022, and our report dated June 6, 2022 expressed an unqualified opinion on those financial statements.

Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
June 6, 2022


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Item 9B.    Other Information

None.

Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Board of Directors of our General Partner

NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

The board of directors of our general partner currently has eight members. The board of directors of our general partner has determined that Mr. James M. Collingsworth, Mr. Stephen L. Cropper, Mr. Bryan K. Guderian and Mr. Derek S. Reiners satisfy the New York Stock Exchange (“NYSE”) and Securities and Exchange Commission (“SEC”) independence requirements. The NYSE does not require a listed publicly traded limited partnership like NGL to have a majority of independent directors on the board of directors of its general partner. In addition, we are not required to have a nominating and corporate governance committee.

In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

experience in business, government, education, technology or public interests;
high-level managerial experience in large organizations;
breadth of knowledge regarding our business and industry;
specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
moral character and integrity;
commitment to our unitholders’ interests;
ability to provide insights and practical wisdom based on experience and expertise;
ability to read and understand financial statements; and
ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

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Directors and Named Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Named executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The following table summarizes information regarding the directors of our general partner and our named executive officers as of June 1, 2022. 
NameAgePosition with NGL Energy Holdings LLC
H. Michael Krimbill68Chief Executive Officer and Director
Linda J. Bridges38Executive Vice President and Chief Financial Officer
John A. Ciolek58Executive Vice President, Strategic Initiatives
Kurston P. McMurray50Executive Vice President and General Counsel and Secretary
Lawrence J. Thuillier51Chief Accounting Officer
Shawn W. Coady60Director
James M. Collingsworth67Director
Stephen L. Cropper72Director
Bryan K. Guderian62Director
John T. Raymond51Director
Derek S. Reiners51Director
Randall S. Wade52Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007, Williams Partners L.P. from 2007 to September 2012, and Pacific Commerce Bank from January 2011 to March 2015.

Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating midstream businesses. Mr. Krimbill also brings financial expertise to the board, including his prior service as a chief financial officer. Mr. Krimbill’s experience serving on other public company boards is also a valuable asset to our board of directors.

Linda J. Bridges. Ms. Bridges has served as our Executive Vice President and Chief Financial Officer since September 30, 2021. Ms. Bridges served as our Senior Vice President, Finance and Treasurer from April 2018 to September 2021. She joined the general partner in June 2016, as Vice President of Finance and Treasurer until she was promoted. Ms. Bridges spent nine years in the commercial division at the Bank of Oklahoma, holding various positions including Vice President - Energy Lending.

John A. Ciolek. Mr. Ciolek joined us in December 2019 and was appointed as our Executive Vice President, Strategic Initiatives, by the board of directors of our general partner in January 2020. Prior to joining NGL, Mr. Ciolek served as Managing Director in the Oil and Gas Group at Credit Suisse Securities LLC (“Credit Suisse”) from August 2015 to October 2019. Before joining Credit Suisse, he served as the Head of the Midstream Franchise within J.P. Morgan’s North American Energy Group starting in May 2011. He previously served for 14 years with Citigroup’s Global Energy Group.

Kurston P. McMurray. Mr. McMurray has served as our Executive Vice President and General Counsel and Secretary since October 2016. Mr. McMurray joined NGL in February 2015 as Vice President, Legal and Corporate Secretary. Prior to joining NGL, Mr. McMurray practiced law in the Tulsa, Oklahoma area since 1998 at firms including Moyers, Martin, Santee, Imel & Tetrick LLP. and Robinett & Osmond and was a founding shareholder of Kurston P. McMurray, PC and Wilkin/McMurray PLLC. Mr. McMurray’s private practice specialized in business transactions, real estate, construction, healthcare, banking, corporate governance, corporate management and commercial litigation.

Lawrence J. Thuillier. Mr. Thuillier has served as our Chief Accounting Officer since January 2016. Prior to joining NGL, Mr. Thuillier served in various roles at Eagle Rock Energy Partners, L.P. from December 2007 through October 2015, most recently as Vice President of Financial Reporting and Corporate Controller. Mr. Thuillier served as Assistant Corporate
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Controller for Exterran Holdings, Inc. (formerly Universal Compression) from November 2006 through November 2007. Prior to that, Mr. Thuillier served in various roles at Deloitte & Touche LLP, most recently as Audit Senior Manager.

Shawn W. Coady. Dr. Coady served as our President and Chief Operating Officer, Retail Division, from April 2012 to March 2018, when we sold a portion of our Retail Propane segment to DCC LPG (“DCC”), and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady served as an executive officer of DCC from April 2018 until his retirement in December 2020. Dr. Coady served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), from March 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicksgas LLC, and the membership interests in Hicksgas LLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until the membership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National Propane Gas Association from 2004 to 2015 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.

Dr. Coady brings valuable operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

James M. Collingsworth. Mr. Collingsworth has served on the board of directors of our general partner since January 2015. Mr. Collingsworth previously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through January 2014. Prior to that, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior to joining Texaco, Mr. Collingsworth was director of feedstocks for Rexene Petrochemical Company from 1988 to 1991 and served in the MAPCO, Inc. organization from 1973 to 1988 in various capacities, including customer service and business development manager of the Mid-America and Seminole pipelines. Mr. Collingsworth served as a director of American Ethane Co. Mr. Collingsworth currently serves on the board of directors of Martin Midstream Partners L.P.

Mr. Collingsworth brings a wealth of in-depth industry experience to the board. Mr. Collingsworth has worked in all facets of the midstream and petrochemical industry for more than 40 years.

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners, L.P. from 2000 through 2005. Since Mr. Cropper’s retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., Berry Petroleum Company, Rental Car Finance Corp., a subsidiary of Dollar Thrifty Automotive Group and Wawa Inc. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation.

Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian currently serves as a Principal of BKG Consulting LLC, an energy related consulting firm. Mr. Guderian has served as Executive Vice President of Business Development of WPX Energy, Inc. (“WPX”) from February 2018 until his retirement in January 2021. Mr. Guderian served as Senior Vice President of Business Development of WPX from October 2014 to February 2018 and as Senior Vice President of Operations of WPX from August 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian served as a director of Apco Oil & Gas International Inc., from 2002 to 2015 and as a director of Petrolera Entre Lomas S.A. from 2003 to 2015.

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

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John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group (“EMG”) of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

Mr. Raymond also currently serves as a director of Ferus Inc., Ferus Natural Gas Fuels Inc., MarkWest Utica EMG, LLC, Medallion Midstream, LLC and PAA GP Holdings LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC.

Mr. Raymond brings extensive financial and industry experience to the board. As a director for other public companies, Mr. Raymond also provides cross board experience.

Derek S. Reiners. Mr. Reiners joined the board of directors of our general partners in December 2019 and was appointed to serve on the Audit Committee. Mr. Reiners currently serves as the President of Contango Energy Capital LLC, a privately held investment and consulting firm. Prior to that, Mr. Reiners served in various senior financial and accounting roles at ONEOK, Inc. and ONEOK Partners, L.P. from August 2009 to May 2019, including Senior Vice President and Chief Accounting Officer from August 2009 to December 2012, Senior Vice President, Chief Financial Officer from January 2013 to May 2017 and Senior Vice President, Finance and Treasurer from June 2017 to May 2019. Prior to joining ONEOK, Mr. Reiners was a partner at Grant Thornton LLP from August 2004 to July 2009. Mr. Reiners is a certified public accountant.

Mr. Reiners brings extensive executive, financial and operational experience to the board. With over ten years of experience in the natural gas liquids industry in numerous positions, Mr. Reiners provides valuable insight into our business and industry.

Randall S. Wade. Mr. Wade has served on the board of directors of our general partner since February 2021. Mr. Wade is the President of EIG Global Energy Partners (“EIG”) and a member of its Investment and Executive Committees. He has broad involvement in the firm’s various activities including investments, investor relations, operations and strategic initiatives. Since joining EIG in 1996, Mr. Wade has filled various roles including Chief Operating Officer, head of the direct lending strategy, investment principal with coverage responsibility for Australia and an analyst for the oil and gas team. Prior to joining EIG, Mr. Wade was a Commercial Lending Officer for First Interstate Bank of Texas, where he was responsible for developing a middle-market loan portfolio.

Mr. Wade brings extensive financial and industry experience to the board.

Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors of our general partner. EMG NGL HC LLC has the right to designate one person to serve on the board of directors of our general partner, and has designated John T. Raymond. EIG has the right to designate one person to serve on the board of directors of our general partner, and has designated Randall S. Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and his brother Todd M. Coady) and the investors who formed the Partnership (“IEP Parties”) (which consists of certain entities controlled by H. Michael Krimbill, and two other investors) each have the right to designate one person to serve on the board of directors of our general partner. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman, although our chief executive officer, Mr. Krimbill, presides over the meetings.

The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors regarding its respective risk oversight role.
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Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

retain and terminate our independent registered public accounting firm;
approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and
establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Mr. Collingsworth, Mr. Cropper, Mr. Guderian, and Mr. Reiners currently serve on the audit committee, and Mr. Reiners serves as the chairman. The board of directors of our general partner has determined that Mr. Reiners is an “audit committee financial expert” as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE and Exchange Act rules.

Compensation Committee

The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include the following, among others:

establishing the general partner’s compensation philosophy and objectives;
approving the compensation of the Chief Executive Officer and other officers;
making recommendations to the board of directors with respect to the directors; and
reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based compensation plans.

Mr. Collingsworth, Mr. Cropper, and Mr. Guderian currently serve on the compensation committee, and Mr. Cropper serves as the chairman. The board of directors of our general partner has determined that Mr. Cropper, Mr. Collingsworth and Mr. Guderian are independent directors under applicable NYSE and Exchange Act rules.

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate Controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

We make available free of charge, within the “Governance” section of our website at www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. Reiners presides over these executive sessions.

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.

Item 11.    Executive Compensation

Compensation Discussion and Analysis

The year “2022” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2022.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. The board of directors has formed a compensation committee to develop our compensation program and to approve the compensation of the Chief Executive Officer and other officers. Our executive officers are also officers of our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our “named executive officers” for fiscal year 2022 were:

H. Michael Krimbill–Chief Executive Officer
Linda J. Bridges–Executive Vice President and Chief Financial Officer (effective September 30, 2021)
Lawrence J. Thuillier–Chief Accounting Officer
Kurston P. McMurray–Executive Vice President and General Counsel and Secretary
John A. Ciolek–Executive Vice President, Strategic Initiatives
Robert W. Karlovich III–Former Executive Vice President and Chief Financial Officer (resigned effective September 30, 2021)

Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer’s contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

Our executive compensation program is designed to provide a total compensation package that allows us to:

Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;
Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and
Reward success in reaching those goals.

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Factors Enhancing Alignment with Unitholder Interests

At risk incentive compensation based on annual financial performance and growth in unitholder value;
No excise tax gross-ups; and
Compensation committee engages an independent compensation adviser.

Compensation Setting Process
Our compensation program for our named executive officers supports our philosophy of pay-for-performance.
Role of Management: Our Chief Executive Officer provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our named executive officers, other than his own.
Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. In March 2021, the compensation committee received compensation advice and data from Pearl Meyer & Partners (“PM&P”). PM&P provided advice and guidance regarding the principal components of compensation for our directors and market salary information for certain executive and senior vice president positions. The compensation committee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted the following:

PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;
PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
Fees paid to PM&P by the Partnership for the services provided in March 2021 were less than 1% of PM&P’s total revenue;
None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;
None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and
None of the PM&P consultants working on Partnership matters own Partnership interests.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis.

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Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. The following table summarizes the primary elements of compensation in our executive compensation program: 
Objective Supported
ElementPrimary PurposeHow Amount DeterminedAttract &
Retain
Motivate &
Pay-for-
Performance
Unitholder
Alignment
Base Salary
Fixed income to compensate executive officers for their level of responsibility, expertise and experience
Based on competition in the marketplace for executive talent and abilities
X
Discretionary Cash Bonus Awards
Rewards achievement of specific annual financial and operational performance goals
Based on the named executive officer’s relative contribution to the ongoing business of the Partnership
XXX
Recognizes individual contributions to our performance
Long-Term Equity Incentive Awards
Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders
Based on the named executive officer’s expected contribution to long-term performance goals
XXX
Provides a forfeitable long-term incentive to encourage executive retention

Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.
Our named executive officers are entitled to the following annual base salaries:
NameFiscal Year Ended
March 31, 2021
Base Salary Rate($)(1)
Fiscal Year Ended
March 31, 2022
Base Salary Rate($)(2)
H. Michael Krimbill625,000 625,000 
Linda J. Bridges— 500,000 
Lawrence J. Thuillier300,000 312,000 
Kurston P. McMurray500,000 500,000 
John A. Ciolek500,000 500,000 
Robert W. Karlovich III500,000 500,000 
(1)    Messrs. Thuillier and McMurray’s base salary rates became effective March 28, 2021. All other named executive officers’ base salary rates were effective April 1, 2020, other than Ms. Bridges who was not serving as a named executive officer during the relevant fiscal year.
(2)    Ms. Bridges base salary rate became effective with her appointment to Executive Vice President and Chief Financial Officer on September 30, 2021. Mr. Thuillier’s base salary rate became effective on January 16, 2022. Mr. Karlovich’s base salary rate for the fiscal year was prorated through September 30, 2021, the date of his resignation from employment. All other named executive officers’ base salary rates were effective April 1, 2021.

Discretionary Cash Bonus Awards

None of the named executive officers is subject to a formal cash bonus plan, and any cash bonuses are at the discretion of the compensation committee of the board of directors. During fiscal year 2022, cash bonuses of $0.3 million were paid to
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both Mr. Ciolek and Mr. McMurray and cash bonuses of $0.2 million were paid to both Ms. Bridges and Mr. Thuillier. Neither Mr. Krimbill nor Mr. Karlovich received a cash bonus during fiscal year 2022.

Long-Term Equity Incentive Awards

The Partnership previously adopted a long-term incentive plan (“LTIP”), which allowed for the issuance of equity-based compensation. The LTIP expired with respect to future awards on May 10, 2021. Prior to expiring, on May 5, 2021, the compensation committee of our board of directors granted certain restricted units to the named executive officers, which vest in tranches, subject to the continued service of the recipients through the vesting date (the “Service Awards”). See “2022 Grants of Plan Based Awards” for details about the number of restricted Service Award units granted in fiscal year 2022 and the relevant vesting terms.

The following table summarizes Service Award units activity for all outstanding Service Award grants during fiscal year 2022 with respect to the named executive officers:
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits VestedUnits ForfeitedMarch 31, 2022
H. Michael Krimbill (1)75,000 250,000 (137,500)— 187,500 
Linda J. Bridges (2)6,250 100,000 (31,250)— 75,000 
Lawrence J. Thuillier (3)5,000 55,000 (18,750)— 41,250 
Kurston P. McMurray (4)10,000 150,000 (47,500)— 112,500 
John A. Ciolek (5)12,500 150,000 (50,000)— 112,500 
Robert W. Karlovich III (6)12,500 150,000 — (162,500)— 
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022. He was granted 250,000 Service Awards on May 5, 2021.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022. She was granted 100,000 Service Awards on May 5, 2021.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022. He was granted 55,000 on May 5, 2021.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022. He was granted 150,000 Service Awards on May 5, 2021.
(6)    Mr. Karlovich was granted 150,000 Service Awards on May 5, 2021. He forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

The following table summarizes the vesting dates of unvested Service Award units at March 31, 2022:
Units by Vesting DateUnvested Units at
NameNovember 14, 2022February 13, 2023November 15, 2023March 31, 2022
H. Michael Krimbill62,500 62,500 62,500 187,500 
Linda J. Bridges25,000 25,000 25,000 75,000 
Lawrence J. Thuillier13,750 13,750 13,750 41,250 
Kurston P. McMurray37,500 37,500 37,500 112,500 
John A. Ciolek37,500 37,500 37,500 112,500 
Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers, other than to Mr. McMurray, who is entitled to receive severance benefits pursuant to his employment agreement in the event of certain terminations of his employment (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”). The board of directors has the option to accelerate the vesting of the Service Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of Service Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the “Outstanding Equity Awards at March 31, 2022” table below (in the “Market Value of Service Award Units that Have Not Yet Vested” column).
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401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. For every dollar that employees contribute up to 4% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employees contribute between 4% and 6% of their eligible compensation (as defined in the plan). Our matching contributions vest over an employee’s first two years of employment, subject to a participant’s continued service.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We offer a benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, vision, disability and life insurance.

Other Officers

Certain officers who have leadership roles within our individual business segments, but who are not executive officers, participate in formulaic bonus programs that are based on the performance of the individual business segments with which they are involved. In most cases, similar programs were in place prior to our acquisition of the businesses, and we have left the programs substantially intact.

Employment Agreements

We do not have employment agreements with any of our named executive officers, other than Mr. McMurray (as described below after the “Summary Compensation Table” under the heading, “Employment Agreement with Mr. McMurray”).

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Internal Revenue Code of 1986, as amended.

Compensation Committee Report

The compensation committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on this review and discussion, the compensation committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this Annual Report. 
Members of the Compensation Committee:
Stephen L. Cropper (Chairman)
James M. Collingsworth
Bryan K. Guderian

Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of executive compensation, as the restricted units are designed to reward the executive officers based on the long-term performance of the Partnership. In combination with our risk management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

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Compensation Committee Interlocks and Insider Participation

During fiscal year 2022, James M. Collingsworth, Stephen L. Cropper, and Bryan K. Guderian served on the compensation committee. None of these individuals is an employee or an officer of our general partner.

Summary Compensation Table

The following table summarizes the compensation earned by our named executive officers for fiscal years 2020 through 2022. 
Name and Position Fiscal
Year
Salary
($)
Bonus
($)
Restricted Unit
Awards
(Service Awards) (1)
($)
All Other
Compensation (2)
($)
Total
($)
H. Michael Krimbill2022625,000 — 537,500 15,719 1,178,219 
Chief Executive Officer2021625,000 — — 17,632 642,632 
2020625,000 1,500,000 1,000,011 11,019 3,136,030 
Linda J. Bridges (3)2022413,846 200,000 215,000 15,632 844,478 
Executive Vice President and
Chief Financial Officer
Lawrence J. Thuillier2022300,692 150,000 118,250 15,353 584,295 
Chief Accounting Officer2021270,000 150,000 — 14,849 434,849 
2020269,923 — 135,004 9,751 414,678 
Kurston P. McMurray2022495,192 250,000 322,500 3,863 1,071,555 
Executive Vice President and2021375,000 600,000 — 9,210 984,210 
General Counsel and Secretary2020374,039 500,000 100,012 8,857 982,908 
John A. Ciolek2022500,000 250,000 322,500 12,374 1,084,874 
Executive Vice President,2021500,000 — — 15,390 515,390 
Strategic Initiatives2020140,385 — 501,250 119 641,754 
Robert W. Karlovich III (4)2022276,923 — 322,500 6,907 606,330 
Executive Vice President and2021500,000 600,000 — 12,759 1,112,759 
Chief Financial Officer2020500,000 500,000 100,012 6,900 1,106,912 
(1)    The fair values of the restricted units shown in the table above were calculated in accordance with FASB Accounting Standards Codification (“ASC”) Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.
(2)    The amounts in this column include matching contributions to our 401(k) plan and taxable group term life insurance.
(3)     Ms. Bridges became Executive Vice President and Chief Financial Officer effective September 30, 2021, and thus was not a named executive officer prior to fiscal year 2022.
(4)    Mr. Karlovich resigned as Executive Vice President and Chief Financial Officer effective September 30, 2021.

Employment Agreement with Mr. McMurray

Mr. McMurray is party to an employment agreement with the Partnership, dated March 10, 2017. The agreement has a term of five years from the effective date, subject to automatic renewals for one-year periods thereafter unless either party provides 60 days’ notice of non-renewal of the term. The agreement was renewed by its terms as of March 10, 2022. The agreement provides that Mr. McMurray will receive a base salary of no less than $250,000 per year and will be eligible to receive an annual bonus with respect to each fiscal year of the Partnership at a target of 100% of his base salary. Mr. McMurray is also entitled to receive annual awards of unvested units under the Partnership’s LTIP.

In the event that Mr. McMurray’s employment is terminated by the Partnership without “cause” (as defined in his agreement), provided that he executes a general release of claims, Mr. McMurray is entitled to receive (i) continued payment of his base salary for 12 months following the termination, (ii) the guaranteed unit awards that would have been paid or granted to Mr. McMurray had Mr. McMurray remained employed for an additional three years following his termination, and (iii) his target annual bonus for the performance year in which his termination occurs. Mr. McMurray would also be entitled to receive
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the severance benefits described in the foregoing sentence in the event that he voluntarily resigns due to a “constructive discharge,” which circumstances would include (1) a reduction of Mr. McMurray’s annual base salary below $250,000 (other than an across-the-board, pro rata reduction of no more than 10% applicable to all similarly situated executive officers of the Partnership) or the Partnership’s failure to provide Mr. McMurray’s elements of compensation, (2) the removal of Mr. McMurray from the position of Executive Vice President and General Counsel and Secretary without Mr. McMurray’s written consent, (3) any action by the Partnership that results in significant diminution of Mr. McMurray’s authority, power or responsibilities, or (4) the Partnership’s relocation of its principal place of business in Oklahoma to a location more than 50 miles from its current location. Mr. McMurray is subject to non-disclosure and intellectual property rights assignment obligations, and an obligation not to solicit customers, employees or consultants lasting during his employment and for a period of 12 months thereafter.

Restricted Unit Awards

During fiscal year 2022, the compensation committee granted Service Awards to the named executive officers.

2022 Grants of Plan Based Awards

The following table summarizes the number of restricted Service Award units granted to our named executive officers, and their grant date fair values:
NameGrant DateTotal Number of Service Award 
Units (#)
Grant Date Fair Value of
Service Award Units
($)(1)
H. Michael KrimbillMay 5, 2021250,000 537,500 
Linda J. BridgesMay 5, 2021100,000 215,000 
Lawrence J. ThuillierMay 5, 202155,000 118,250 
Kurston P. McMurrayMay 5, 2021150,000 322,500 
John A. CiolekMay 5, 2021150,000 322,500 
Robert W. Karlovich IIIMay 5, 2021150,000 322,500 
(1)    The fair values of the restricted Service Award units shown in the table above were calculated in accordance with ASC Topic 718, Stock Compensation, and does not represent the amount actually realized by the named executive officer at vesting, which may be more or less than the amount reported in the table above. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report.

The 2022 Service Awards vest and settle in common units. During fiscal year 2022, the compensation committee granted Service Awards to the named executive officers for which units vest in substantially equal installments on February 10, 2022, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service of the recipients through each such vesting date.

Outstanding Equity Awards at March 31, 2022

The following table summarizes the number of unvested Service Awards outstanding and their fair values at March 31, 2022:
Number of Service Award Units
that Have Not Yet Vested
Market Value of Service Award Units
that Have Not Yet Vested
Name(#)(1)($)(2)
H. Michael Krimbill187,500 416,250 
Linda J. Bridges75,000 166,500 
Lawrence J. Thuillier41,250 91,575 
Kurston P. McMurray112,500 249,750 
John A. Ciolek112,500 249,750 
Robert W. Karlovich III (3)— — 
(1)    Reflects Service Awards that have not vested and are held by each named executive officer. The outstanding Service Awards units vest in substantially equal installments on November 14, 2022, February 13, 2023 and November 15, 2023.
(2)    Calculated based on the closing market price of our common units at March 31, 2022 of $2.22. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.
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(3)    Mr. Karlovich resigned effective September 30, 2021 resulting in the forfeiture of his Service Awards. As a result, Mr. Karlovich did not have any outstanding equity awards as of March 31, 2022.

2022 Units Vested

During fiscal year 2022, certain of the restricted Service Awards vested. The following table summarizes the value of the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates.
NameNumber of Service Award Units
Acquired on Vesting
(#)
Value Realized on Vesting
($)
H. Michael Krimbill (1)137,500 379,500 
Linda J. Bridges (2)31,250 63,250 
Lawrence J. Thuillier (3)18,750 25,300 
Kurston P. McMurray (4)47,500 43,925 
John A. Ciolek (5)50,000 63,250 
Robert W. Karlovich III (6)— — 
(1)    Mr. Krimbill vested in 75,000 Service Awards on November 12, 2021 and 62,500 Service Awards on February 10, 2022.
(2)    Ms. Bridges vested in 6,250 Service Awards on November 12, 2021 and 25,000 Service Awards on February 10, 2022.
(3)    Mr. Thuillier vested in 5,000 Service Awards on November 12, 2021 and 13,750 Service Awards on February 10, 2022.
(4)    Mr. McMurray vested in 10,000 Service Awards on November 12, 2021 and 37,500 Service Awards onFebruary 10, 2022.
(5)    Mr. Ciolek vested in 12,500 Service Awards on November 12, 2021 and 37,500 Service Awards on February 10, 2022.
(6)    Mr. Karlovich forfeited all outstanding Service Awards upon his resignation from employment on September 30, 2021.

Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing common units. The following table summarizes the number of common units issued and the number of common units withheld for taxes:
NameNumber of Units
Issued
Number of Units
Withheld
Total
H. Michael Krimbill137,500 — 137,500 
Linda J. Bridges16,753 14,497 31,250 
Lawrence J. Thuillier10,489 8,261 18,750 
Kurston P. McMurray25,489 22,011 47,500 
John A. Ciolek50,000 — 50,000 

Potential Payments Upon Termination or Change in Control

We do not provide any severance or change of control benefits to our named executive officers, other than Mr. McMurray, who is entitled to receive severance benefits for certain types of terminations (as described in more detail above under the heading, “Employment Agreement with Mr. McMurray”). In the event that Mr. McMurray’s employment had been terminated as of March 31, 2022 by the Partnership without “cause” or due to a “constructive discharge,” Mr. McMurray would have been entitled to receive the following amounts:
Cash SeveranceValue of Guaranteed Unit AwardsTarget Annual BonusTotal
$500,000 $249,750 $500,000 $1,249,750 

The board of directors has the option to accelerate the vesting of the Service Awards in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of Service Awards upon a change in control, that hypothetically occurred on March 31, 2022, the value of such units would be the same as reported in the “Outstanding Equity Awards at March 31, 2022” table above (in the “Market Value of Service Award Units that Have Not Yet Vested” column).

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Pay Ratio Disclosure

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information regarding the ratio of the annual total compensation of our Chief Executive Officer, Mr. Krimbill, to the median of the annual total compensation of our employees for our last fiscal year.

For the year ended March 31, 2022:

The median of the annual total compensation of all employees (other than the Chief Executive Officer) was $88,063; and
The annual total compensation of Mr. Krimbill, as reported in the Summary Compensation Table above, was $1,178,219.

Based on the information for the year ended March 31, 2022, the ratio of the annual total compensation of our Chief Executive Officer to the annual total compensation of our median employee was approximately 13 to 1.

To determine our median employee, we identified each individual employed by us on January 1, 2022, our determination date. As of that date, we had 876 employees located in two countries. We identified the median employee by examining only base pay plus overtime for the period from January 1, 2021 through December 31, 2021. We included all employees, with the exception of four employees that work in Canada, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions or adjustments to any base pay plus overtime amounts. After identifying the median employee, we calculated the annual total compensation for the median employee using the same methodology we use to calculate total annual compensation for our named executive officers, as set forth in the Summary Compensation Table above.

This pay ratio is a reasonable estimate calculated in a manner consistent with SEC rules based on our payroll and employment records and the methodology described above. The SEC rules for identifying the median employee and calculating the pay ratio based on that employee’s annual total compensation allow companies to adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices. As such, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

Hedging of Partnership Common Units

Our Supplemental Trading Policy prohibits directors, named executive offices and other designated employees from engaging in hedging activities with respect to our common units.

Director Compensation

Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following cash compensation for his board service:

an annual retainer of $80,000;
an annual retainer of $20,000 for the chairman of the audit committee;
an annual retainer of $15,000 for the chairman of the compensation committee;
an annual retainer of $14,000 for each member of the audit committee other than the chairman; and
an annual retainer of $10,000 for each member of the compensation committee other than the chairman.

In addition, each director who is not an officer or employee of our general partner or its affiliates has been granted awards of restricted units. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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The following table summarizes the compensation earned during fiscal year 2022 by each director who is not an officer or employee of our general partner or its affiliates:
NameFees Earned or
Paid in Cash
($)
Restricted Unit
Awards
($)(1)
Total
($)
Shawn W. Coady80,000 107,500 187,500 
James M. Collingsworth104,000 107,500 211,500 
Stephen L. Cropper109,000 107,500 216,500 
Bryan K. Guderian104,000 107,500 211,500 
Derek S. Reiners100,000 107,500 207,500 
(1)    The amounts reflected in this column represent the grant date fair value of each director’s May 5, 2021 award of 50,000 restricted units, which were calculated in accordance with ASC Topic 718, Stock Compensation. For a discussion of the assumptions and methodologies used in calculating the grant date fair value of the restricted unit awards, see Note 9 to our consolidated financial statements included in this Annual Report. See table below for discussion of the vesting of these grants.

Long-Term Equity Incentive Awards

The following table summarizes Service Award units activity during fiscal year 2022 with respect to each director who is not an officer or employee of our general partner or its affiliates:
Unvested Units atUnvested Units at
NameMarch 31, 2021Units GrantedUnits Vested (1)March 31, 2022 (2)
Shawn W. Coady4,000 50,000 (16,500)37,500 
James M. Collingsworth4,000 50,000 (16,500)37,500 
Stephen L. Cropper4,000 50,000 (16,500)37,500 
Bryan K. Guderian4,000 50,000 (16,500)37,500 
Derek S. Reiners4,000 50,000 (16,500)37,500 
(1)    4,000 Service Awards vested on November 12, 2021 and 12,500 Service Awards vested on February 10, 2022.
(2)    12,500 Service Awards will vest on November 14, 2022, 12,500 Service Awards will vest on February 13, 2023 and 12,500 Service Awards will vest on November 15, 2023, subject to the continued service of the recipients through each such vesting date.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table summarizes the beneficial ownership, as of June 1, 2022, of our common units by:

each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;
each director of our general partner;
each named executive officer of our general partner; and
all directors and executive officers of our general partner as a group.
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Beneficial OwnersCommon Units
Beneficially
Owned
Percentage of
Common Units
Beneficially
Owned (1)
5% or greater unitholders (other than officers and directors):  
Invesco Ltd. (2)19,717,009 15.09 %
EIG Neptune Equity Aggregator, L.P. (3)16,734,375 11.35 %
Directors and named executive officers:  
Linda J. Bridges (4)62,165 *
John A. Ciolek (5)194,764 *
Shawn W. Coady (6)2,614,695 2.00 %
James M. Collingsworth (7)352,370 *
Stephen L. Cropper (8)87,500 *
Bryan K. Guderian85,000 *
H. Michael Krimbill (9)4,127,518 3.16 %
Kurston P. McMurray (10)84,231 *
John T. Raymond50,000 *
Derek S. Reiners38,500 *
Lawrence J. Thuillier (11)60,319 *
Randall S. Wade— *
All directors and executive officers as a group (12 persons) (12)7,757,062 5.94 %
* Less than 1.0%
(1)    Based on 130,695,970 common units outstanding at June 1, 2022.
(2)    The mailing address for Invesco Ltd. is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. Invesco Ltd. reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to Invesco Ltd. is based upon its Schedule 13G/A filed with the SEC on February 10, 2022.
(3)    The mailing address for EIG Neptune Equity Aggregator, L.P. (“EIG Neptune”) is 600 New Hampshire Ave NW, Suite 1200, Washington, DC 20037. EIG Neptune reported sole voting and dispositive power with respect to all common units beneficially owned. The information related to EIG Neptune is based upon its Schedule 13D/A filed with the SEC on September 4, 2020. The common units beneficially owned relate to warrants that were exercisable on July 2, 2020. For purposes of calculating ownership percentages, the units underlying the warrants are only deemed outstanding for purposes of calculating EIG Neptune’s percentage.
(4)    Does not include 75,000 unvested units, of which 25,000 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(5)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(6)    Dr. Coady owns 134,804 of these common units. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole member. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 of these common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 of these common units. Dr. Coady also owns a12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(7)    Mr. Collingsworth owns 340,000 of these common units. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 9,500 of these common units. Cindy Collingsworth owns 870 of these common units.
(8)Mr. Cropper owns 62,500 of these common units. The Donna L. Cropper Revocable Living Trust, of which Mr. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.
(9)    Mr. Krimbill owns 2,241,115 of these common units, which does not include 187,500 unvested units, of which 62,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. All of the unvested units noted above were reported on Mr. Krimbill’s Form 4. Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP also owns 488,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to
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have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Krimbill Enterprises LP, II also owns 130,000 of these common units. Krimbill Enterprises LP, II is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests.
(10)    Does not include 112,500 unvested units, of which 37,500 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date. Mr. McMurray owns a 0.25% interest in our general partner through MCM Investments, LLC, of which he owns 100% of the membership interests.
(11)    Does not include 41,250 unvested units, of which 13,750 will vest on each of the following dates, November 14, 2022, February 13, 2023 and November 15, 2023, subject to the continued service through each such vesting date.
(12)    The directors and executive officers of our general partner also collectively own a 29.69% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2022.
Number of Securities to be
Issued upon Exercise of
Outstanding Options,
Warrants and Rights
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
Number of Securities
Remaining Available for
Future Issuances Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
Plan Category (a)(b)(c)
Equity Compensation Plans Approved by Security Holders— — — 
Equity Compensation Plans Not Approved by Security Holders (1)2,188,800 — — 
Total2,188,800 — — 
(1)    Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011, which did not require the approval of our unitholders. Prior to the expiration of the LTIP on May 10, 2021, we granted approximately 3.3 million common units as Service Awards, which will vest in our 2023 and 2024 fiscal years. Due to the LTIP expiring, we have no common units available for grant and any current unvested Service Awards that are forfeited or canceled will not be available for future grants.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 44,208,446 common units, representing an aggregate 33.83% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distribution rights (“IDRs”). As of March 31, 2022, we owned 8.69% of our general partner.

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount of these expenses. In addition, our general partner owns the 0.1% general partner interest and all of the IDRs. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

The following table summarizes the distributions and payments to be made by us to our directors, executive officers, and greater than 5% unitholders and our general partner in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.
108


Operation Stage
Distributions of available cash to our directors, executive officers, and greater than 5% unitholders and our general partnerWe generally make cash distributions 99.9% to our unitholders pro rata, including our directors, executive officers, and greater than 5% unitholders as the holders of an aggregate 44,208,446 common units, and 0.1% to our general partner. In addition, when distributions exceed the minimum quarterly distribution and other higher target distributions levels, our general partner is entitled to increasing percentages of the distributions, up to 48.1% of the distributions above the highest target distribution level.
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
As described in Note 7 to our consolidated financial statements included in this Annual Report, the indenture to the 2026 Senior Secured Notes restricts us from paying 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. In addition, quarterly distributions on the preferred units must be fully paid for all preceding fiscal quarters before we are permitted to declare or pay any distributions on our common units.
Payments to our general partner and its affiliatesOur general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. As the sole purpose of the general partner is to act as our general partner, substantially all of the expenses of our general partner are incurred on our behalf and reimbursed by us or our subsidiaries. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partnerIf our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
LiquidationUpon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Transactions with Related Persons

We purchase goods and services from certain entities that are partially owned by our named executive officers. The following table summarizes these transactions from April 1, 2021 to March 31, 2022:
EntityNature of PurchasesAmount PurchasedOwnership Interest in Entity
(in thousands)
H. Michael Krimbill
KAIR2014 LLC (“KAIR2014”)Aircraft$670 50 %

In connection with the purchase of our 50% interest in an aircraft company, KAIR2014, we executed a joint and several guarantee for the benefit of the lender for KAIR2014’s outstanding loan. The other owner of KAIR2014, our Chief Executive Officer, H. Michael Krimbill, 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 March 31, 2022, the outstanding balance of the loan is approximately $2.5 million. Payments are made monthly, reducing the outstanding balance, 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 March 31, 2022, no accrual has been recorded related to this guarantee.
109



Travis Krimbill, an employee of the Partnership, is the son of H. Michael Krimbill, who is a named executive officer of the Partnership and a member of the board of directors. Travis Krimbill does not report to H. Michael Krimbill and his compensation is determined by the Chief Financial Officer. During the year ended March 31, 2022, Travis Krimbill received total compensation of approximately $0.2 million.

Registration Rights Agreement

We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registration rights parties”) pursuant to which we agreed to register for resale under the Securities Act of 1933, as amended (“Securities Act”) common units owned by the parties to the Registration Rights Agreement. In connection with our IPO, we granted registration rights to the NGL Energy GP Investor Group, and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if an exemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject to limitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following:

Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that they continue to own more than 4% of our common units, require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file a total of nine registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million.
Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.
Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies for the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers will make all reasonable efforts to cancel or annul the transaction.

The Code of Business Conduct and Ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to:

whether there is an appropriate business justification for the transaction;
the benefits that accrue to the Partnership as a result of the transaction;
the terms available to unrelated third parties entering into similar transactions;
the impact of the transaction on a director’s independence (in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer);
the availability of other sources for comparable products or services;
110


whether it is a single transaction or a series of ongoing, related transactions; and
whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

Director Independence

The NYSE does not require a listed publicly traded limited partnership like NGL to have a majority of independent directors on the board of directors of its general partner. For a discussion of the independence of the board of directors of our general partner, see Part III, Item 10–“Directors, Executive Officers and Corporate Governance–Board of Directors of our General Partner.”

Item 14.    Principal Accountant Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Grant Thornton LLP to audit our annual consolidated financial statements and for other services for the periods indicated:
March 31,
20222021
(in thousands)
Audit fees (1)$1,882 $2,149 
Audit-related fees (2)— 
Tax fees— — 
All other fees— — 
Total$1,882 $2,156 
(1)    Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.
(2)    Includes fees in fiscal year 2021 for review services for one of our subsidiaries.

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.

111


PART IV
Item 15.    Exhibit and Financial Statement Schedules

(a)    The following documents are filed as part of this Annual Report:
1.    Financial Statements. See the accompanying Index to Financial Statements.
2.    Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.
3.    Exhibits.
Exhibit NumberDescription
2.1
2.2
2.3
2.4
2.5
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
112


Exhibit NumberDescription
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
113


Exhibit NumberDescription
4.20
4.21
4.22*
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32*
4.33
4.34
4.35
4.36
4.37
4.38
114


Exhibit NumberDescription
4.39
4.40*
4.41
4.42
4.43*
4.44
4.45
4.46
4.47*
10.1
10.2
10.3*
10.4*
10.5
10.6+
10.7+
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
115


Exhibit NumberDescription
10.16
21.1*
22.1*
23.1*
31.1*
31.2*
32.1*
32.2*
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
104Cover 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) Consolidated Balance Sheets at March 31, 2022 and 2021, (ii) Consolidated Statements of Operations for the years ended March 31, 2022, 2021, and 2020, (iii) Consolidated Statements of Comprehensive Loss for the years ended March 31, 2022, 2021, and 2020, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2022, 2021, and 2020, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2022, 2021, and 2020, and (vi) Notes to Consolidated Financial Statements.
+    Management contracts or compensatory plans or arrangements.

Item 16.    Form 10-K Summary

None.
116


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on June 6, 2022.
NGL ENERGY PARTNERS LP
By:NGL Energy Holdings LLC, its general partner
By:/s/ H. Michael Krimbill
H. Michael Krimbill
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ H. Michael KrimbillChief Executive Officer and DirectorJune 6, 2022
H. Michael Krimbill(Principal Executive Officer)
/s/ Linda J. BridgesChief Financial OfficerJune 6, 2022
Linda J. Bridges(Principal Financial Officer)
/s/ Lawrence J. ThuillierChief Accounting OfficerJune 6, 2022
Lawrence J. Thuillier(Principal Accounting Officer)
/s/ Shawn W. CoadyDirectorJune 6, 2022
Shawn W. Coady
/s/ James M. CollingsworthDirectorJune 6, 2022
James M. Collingsworth
/s/ Stephen L. CropperDirectorJune 6, 2022
Stephen L. Cropper
/s/ Bryan K. GuderianDirectorJune 6, 2022
Bryan K. Guderian
/s/ John T. RaymondDirectorJune 6, 2022
John T. Raymond
/s/ Derek S. ReinersDirectorJune 6, 2022
Derek S. Reiners
/s/ Randall S. WadeDirectorJune 6, 2022
Randall S. Wade
117


INDEX TO FINANCIAL STATEMENTS
NGL Energy Partners LP
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
F-2
Consolidated Balance Sheets at March 31, 2022 and 2021
F-4
Consolidated Statements of Operations for the years ended March 31, 2022, 2021, and 2020
F-5
Consolidated Statements of Comprehensive Loss for the years ended March 31, 2022, 2021, and 2020
F-6
Consolidated Statements of Changes in Equity for the years ended March 31, 2022, 2021, and 2020
F-7
Consolidated Statements of Cash Flows for the years ended March 31, 2022, 2021, and 2020
F-8
Notes to Consolidated Financial Statements
F-9

F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of NGL Energy Holdings LLC and
Unitholders of NGL Energy Partners LP

Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2022 and 2021, the related consolidated statements of operations, comprehensive loss, changes in equity, and cash flows for each of the three years in the period ended March 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of March 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of March 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated June 6, 2022 expressed an unqualified opinion.

Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill Impairment Assessment
As described further in Note 5 to the consolidated financial statements, the Partnership’s consolidated goodwill balance was $744.4 million as of March 31, 2022. Management evaluates goodwill for impairment on January 1 of each year, or more frequently to the extent events or conditions indicate a risk of possible impairment. Management performed a quantitative impairment assessment for the Crude Oil Logistics reporting unit to test goodwill for impairment as of January 1, 2022. As a result of the assessment performed for the reporting unit, and as described further in Note 5 to the consolidated financial statements, the Partnership concluded the fair value of the Crude Oil Logistics reporting unit exceeded its carrying value and no goodwill impairment was recorded. We identified the goodwill impairment assessment as a critical audit matter.

The principal considerations for our determination that the goodwill impairment assessment was a critical audit matter are that there was a high estimation uncertainty due to significant judgments with respect to assumptions used to estimate the future revenues and cash flows, including revenue growth rates, operating expenses and cash outflows necessary to support the cash flows, weighted average costs of capital and future market conditions as well as the valuation methodologies applied by the Partnership. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to management’s forecasted future revenues and cash flows. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
F-2



Our audit procedures related to the goodwill impairment assessment included the following, among others. We tested the effectiveness of controls relating to management’s goodwill impairment tests, including controls over the determination of the fair value of the reporting unit. In addition to testing the effectiveness of controls, we also performed the following:

Utilized a valuation specialist to evaluate:
The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing an independent calculation,
The appropriateness of the discount rate by recalculating the weighted average costs of capital and evaluating future market conditions, and
Other significant assumptions, including the terminal growth rate.
Tested the reasonableness of management’s process for determining the fair value of the reporting unit, including the revenue growth rate, forecasted costs and operating margins by comparing such items to the industry projections and conditions found in industry reports as well as historical operating results of the reporting unit and by assessing the likelihood or capability of the reporting unit to undertake activities or initiatives underpinning significant drivers of growth in the forecasted period.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2010.

Tulsa, Oklahoma
June 6, 2022

F-3


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Balance Sheets
(in Thousands, except unit amounts)
March 31,
20222021
ASSETS
CURRENT ASSETS:
Cash and cash equivalents$3,822 $4,829 
Accounts receivable-trade, net of allowance for expected credit losses of $2,626 and $2,192, respectively1,123,163 725,943 
Accounts receivable-affiliates8,591 9,435 
Inventories251,277 158,467 
Prepaid expenses and other current assets159,486 109,164 
Total current assets1,546,339 1,007,838 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $887,006 and $776,279, respectively2,462,390 2,706,853 
GOODWILL744,439 744,439 
INTANGIBLE ASSETS, net of accumulated amortization of $507,285 and $517,518, respectively1,135,354 1,262,613 
INVESTMENTS IN UNCONSOLIDATED ENTITIES21,897 22,719 
OPERATING LEASE RIGHT-OF-USE ASSETS114,124 152,146 
OTHER NONCURRENT ASSETS45,802 50,733 
Total assets$6,070,345 $5,947,341 
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade$1,084,837 $679,868 
Accounts payable-affiliates73 119 
Accrued expenses and other payables140,719 170,400 
Advance payments received from customers7,934 11,163 
Current maturities of long-term debt2,378 2,183 
Operating lease obligations41,261 47,070 
Total current liabilities1,277,202 910,803 
LONG-TERM DEBT, net of debt issuance costs of $42,988 and $55,555, respectively, and current maturities3,350,463 3,319,030 
OPERATING LEASE OBLIGATIONS72,784 103,637 
OTHER NONCURRENT LIABILITIES104,346 114,615 
COMMITMENTS AND CONTINGENCIES (NOTE 8)00
CLASS D 9.00% PREFERRED UNITS, 600,000 and 600,000 preferred units issued and outstanding, respectively551,097 551,097 
EQUITY:
General partner, representing a 0.1% interest, 130,827 and 129,724 notional units, respectively(52,478)(52,189)
Limited partners, representing a 99.9% interest, 130,695,970 and 129,593,939 common units issued and outstanding, respectively401,486 582,784 
Class B preferred limited partners, 12,585,642 and 12,585,642 preferred units issued and outstanding, respectively305,468 305,468 
Class C preferred limited partners, 1,800,000 and 1,800,000 preferred units issued and outstanding, respectively42,891 42,891 
Accumulated other comprehensive loss(308)(266)
Noncontrolling interests17,394 69,471 
Total equity714,453 948,159 
Total liabilities and equity$6,070,345 $5,947,341 
The accompanying notes are an integral part of these consolidated financial statements.
F-4


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Operations
(in Thousands, except unit and per unit amounts)
Year Ended March 31,
202220212020
REVENUES:
Water Solutions$544,866 $370,986 $422,059 
Crude Oil Logistics2,505,496 1,721,636 2,549,767 
Liquids Logistics4,897,553 3,133,146 4,611,136 
Corporate and Other— 1,255 1,038 
Total Revenues7,947,915 5,227,023 7,584,000 
COST OF SALES:
Water Solutions33,980 9,622 (33,870)
Crude Oil Logistics2,352,932 1,515,993 2,293,953 
Liquids Logistics4,752,400 2,966,391 4,342,526 
Corporate and Other— 1,816 1,774 
Total Cost of Sales7,139,312 4,493,822 6,604,383 
OPERATING COSTS AND EXPENSES:
Operating285,535 254,562 332,993 
General and administrative63,546 70,468 113,664 
Depreciation and amortization288,720 317,227 265,312 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Revaluation of liabilities(6,495)6,261 9,194 
Operating Income (Loss)83,043 (390,753)(3,332)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities1,400 1,938 1,291 
Interest expense(271,640)(198,799)(181,184)
Gain (loss) on early extinguishment of liabilities, net1,813 (16,692)1,341 
Other income (expense), net2,254 (36,503)1,684 
Loss From Continuing Operations Before Income Taxes(183,130)(640,809)(180,200)
INCOME TAX (EXPENSE) BENEFIT(971)3,391 (345)
Loss From Continuing Operations(184,101)(637,418)(180,545)
Loss From Discontinued Operations, net of Tax— (1,769)(218,235)
Net Loss(184,101)(639,187)(398,780)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS(655)(632)1,773 
NET LOSS ATTRIBUTABLE TO NGL ENERGY PARTNERS LP$(184,756)$(639,819)$(397,007)
NET LOSS FROM CONTINUING OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(730,683)$(367,246)
NET LOSS FROM DISCONTINUED OPERATIONS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$— $(1,767)$(218,017)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS (NOTE 3)$(288,630)$(732,450)$(585,263)
BASIC LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
DILUTED LOSS PER COMMON UNIT
Loss From Continuing Operations$(2.22)$(5.67)$(2.88)
Loss From Discontinued Operations, net of Tax$— $(0.01)$(1.71)
Net Loss$(2.22)$(5.68)$(4.59)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING129,840,234 128,980,823 127,411,908 
 The accompanying notes are an integral part of these consolidated financial statements.
F-5


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
(in Thousands)
Year Ended March 31,
202220212020
Net loss$(184,101)$(639,187)$(398,780)
Other comprehensive (loss) income(42)119 (130)
Comprehensive loss$(184,143)$(639,068)$(398,910)

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

F-6


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended March 31, 2022, 2021, and 2020
(in Thousands, except unit amounts)
Limited Partners
PreferredCommon
General
Partner
UnitsAmount
Units
AmountAccumulated Other Comprehensive Income (Loss)Noncontrolling
Interests
Total
Equity
BALANCES AT MARCH 31, 2019$(50,603)8,400,000 $202,731 124,508,497 $2,067,197 $(255)$58,748 $2,277,818 
Distributions to general and common unit partners and preferred unitholders (Note 9)(342)— — — (258,020)— — (258,362)
Distributions to noncontrolling interest owners— — — — — — (1,145)(1,145)
Issuance of Class B preferred units, net of offering costs (Note 9)— 4,185,642 102,737 — — — — 102,737 
Issuance of Class C preferred units, net of offering costs (Note 9)— 1,800,000 42,891 — — — — 42,891 
Issuance of warrants, net of offering costs (Note 9)— — — — 52,742 — — 52,742 
Warrants exercised (Note 9)— — — 1,458,371 15 — — 15 
Accretion of beneficial conversion feature of 10.75% Class A convertible preferred units (Note 9)— — — — (36,517)— — (36,517)
10.75% Class A convertible preferred units redemption - amount paid in excess of carrying value (Note 9)— — — — (78,797)— — (78,797)
Equity issued pursuant to incentive compensation plan33 — — 2,938,481 32,931 — — 32,964 
Common unit repurchases and cancellations— — — (133,634)(1,644)— — (1,644)
Mesquite Disposals Unlimited, LLC ("Mesquite") acquisition— — — — — — 17,124 17,124 
Investment in NGL Energy Holdings LLC (Note 12)— — — — (15,226)— — (15,226)
Net loss(478)— — — (396,529)— (1,773)(398,780)
Other comprehensive loss— — — — — (130)— (130)
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 (Note 9)(65)— — — (147,715)— — (147,780)
Distributions to noncontrolling interest owners— — — — — — (4,115)(4,115)
Common unit repurchases and cancellations— — — (70,226)(182)— — (182)
Equity issued pursuant to incentive compensation plan— — — 892,450 4,727 — — 4,727 
Net (loss) income(733)— — — (639,086)— 632 (639,187)
Other comprehensive income— — — — — 119 — 119 
Cumulative effect adjustment for adoption of ASU 2016-13 (Note 16)(1)— — — (1,112)— — (1,113)
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— — — — — — (1,635)(1,635)
Sawtooth joint venture disposition (Note 17)— — — — — — (51,097)(51,097)
Common unit repurchases and cancellations (Note 9)— — — (44,769)(90)— — (90)
Equity issued pursuant to incentive compensation plan (Note 9)— — — 1,146,800 3,259 — — 3,259 
Net (loss) income(289)— — — (184,467)— 655 (184,101)
Other comprehensive loss— — — — — (42)— (42)
BALANCES AT MARCH 31, 2022$(52,478)14,385,642 $348,359 130,695,970 $401,486 $(308)$17,394 $714,453 
The accompanying notes are an integral part of these consolidated financial statements.
F-7


NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in Thousands)
Year Ended March 31,
202220212020
OPERATING ACTIVITIES:
Net loss$(184,101)$(639,187)$(398,780)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations, net of tax— 1,769 218,235 
Depreciation and amortization, including amortization of debt issuance costs306,208 331,200 276,848 
(Gain) loss on early extinguishment or revaluation of liabilities, net(8,308)22,953 7,853 
Non-cash equity-based compensation expense(1,052)6,727 26,510 
Loss on disposal or impairment of assets, net94,254 475,436 261,786 
Change in provision for expected credit losses929 5,988 1,002 
Net adjustments to fair value of commodity derivatives116,556 83,578 (85,941)
Equity in earnings of unconsolidated entities(1,400)(1,938)(1,291)
Distributions of earnings from unconsolidated entities2,205 3,364 — 
Lower of cost or net realizable value adjustments14,761 3,898 33,973 
Other2,310 1,513 2,541 
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates(397,607)(162,031)436,349 
Inventories(119,806)(92,731)29,779 
Other current and noncurrent assets40,158 92,555 14,081 
Accounts payable-trade and affiliates405,420 207,505 (375,257)
Other current and noncurrent liabilities(64,681)(34,836)(65,262)
Net cash provided by operating activities-continuing operations205,846 305,763 382,426 
Net cash (used in) provided by operating activities-discontinued operations— (1,769)81,629 
Net cash provided by operating activities205,846 303,994 464,055 
INVESTING ACTIVITIES:
Capital expenditures(142,359)(186,801)(555,713)
Acquisitions, net of cash acquired— 901 (1,268,474)
Net settlements of commodity derivatives(152,055)(80,372)86,702 
Proceeds from sales of assets18,500 45,742 17,621 
Proceeds from divestitures of businesses and investments, net63,489 — — 
Investments in unconsolidated entities(350)(963)(21,218)
Distributions of capital from unconsolidated entities367 — 440 
Repayments on loan for natural gas liquids facility— — 3,022 
Net cash used in investing activities-continuing operations(212,408)(221,493)(1,737,620)
Net cash provided by investing activities-discontinued operations— — 298,864 
Net cash used in investing activities(212,408)(221,493)(1,438,756)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities1,815,000 1,261,000 4,074,000 
Payments on revolving credit facilities(1,703,000)(2,727,000)(3,775,000)
Issuance of senior secured and unsecured notes and term credit agreement— 2,300,000 700,000 
Repayment of term credit agreements— (555,562)— 
Repayment and repurchase of senior unsecured notes(83,167)(115,796)(454)
Proceeds from borrowings on other long-term debt— 50,000 — 
Payments on other long-term debt(7,390)(5,590)(653)
Debt issuance costs(12,932)(65,566)(14,950)
Distributions to general and common unit partners and preferred unitholders— (142,128)(244,400)
Distributions to noncontrolling interest owners(1,635)(4,115)(1,145)
Proceeds from sale of preferred units, net of offering costs— — 622,391 
Payments for redemption of preferred units— — (265,128)
Common unit repurchases and cancellations(90)(182)(1,644)
Payments to settle contingent consideration liabilities(1,231)(95,437)(98,958)
Investment in NGL Energy Holdings LLC— — (15,226)
Net cash provided by (used in) financing activities5,555 (100,376)978,833 
Net (decrease) increase in cash and cash equivalents(1,007)(17,875)4,132 
Cash and cash equivalents, beginning of period4,829 22,704 18,572 
Cash and cash equivalents, end of period$3,822 $4,829 $22,704 
Supplemental cash flow information:
Cash interest paid$254,814 $168,642 $155,445 
Income taxes paid (net of income tax refunds)$2,480 $2,586 $4,931 
Supplemental non-cash investing and financing activities:
Distributions declared but not paid to preferred unitholders$— $13,814 $18,687 
Accrued capital expenditures$14,558 $21,824 $88,917 
The accompanying notes are an integral part of these consolidated financial statements.
F-8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 1—Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At March 31, 2022, our operations included 3 segments:

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle 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 owned and leased 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 owned terminals, third-party storage and terminal facilities, 9 common carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and expect to commence operations on our propane pipeline in Michigan in June 2022.

Note 2—Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The accompanying 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 consolidated financial statements.

Use of Estimates

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

Critical accounting estimates we make in the preparation of our consolidated financial statements include, among others, determining the impairment of goodwill and long-lived assets, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the fair value of derivative instruments, estimating certain revenues, the fair value of asset retirement obligations, the fair value of assets and liabilities acquired in acquisitions, the recoverability of inventories, the collectibility of accounts and notes receivable and accruals for environmental matters. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

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

F-9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


In February 2016, the FASB issued ASC 842, “Leases.” This will replace previous lease accounting guidanceLevel 1: Quoted prices in GAAP. The new guidance requires the recognition of lease assets and lease liabilities by lesseesactive markets for those leases classified as operating leases. It also retains a distinction between finance leases and operating leases. This guidance is effective for the Partnership beginning April 1, 2019. We evaluated our current leases and other contracts that may be considered leases under the new standard and the impact on our internal controls, accounting policies and financial statements and disclosures. Our evaluation process includes compiling a database of our leases, implementing accounting software to assist with compliance and developing internal controls to ensure completeness and accuracy of our leases meeting the scope of ASC 842. Based on our current population of leases, we expect the impact of ASC 842 to increase ouridentical assets and liabilities that we have the ability to access at the measurement date.
Level 2: Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by between $533 millioncorrelation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and $563 million dueoption contracts and forward commodity contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the recognitionpricing models include publicly available prices and forward curves generated from a compilation of right-of-use assetsdata gathered from third parties.
Level 3: Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and lease liabilities. We elected the following transitional practical expedients, which will allow uslowest priority to not evaluate land easements priorunobservable inputs (Level 3). In some cases, the inputs used to April 1, 2019: use hindsightmeasure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in determining the lease term;fair value hierarchy. Assessing the significance of a particular input to not reassess whether current or expired contracts contain leases; to not reassess the lease classification for any expired or existing leases; and to not reassess initial costs. We also expect to elect the optional transition method to record the adoption impact through a cumulative effect adjustment to equity.

On April 1, 2018, we adopted ASC 606, “Revenue from Contracts with Customers,” using a modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in Topic 605, “Revenue Recognition,” and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. To achieve this core principle, morefair value measurement requires judgment, and estimates are required within the revenue recognition process than required under Topic 605. In addition, ASC 606 requires significantly expanded disclosures relatedconsidering factors specific to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See asset or liability.
Note 15 for a further discussion of the impact of adoption of ASC 606 on our consolidated financial statements and our revenue recognition policies.

Derivative Financial Instruments
On April 1, 2018, we adopted ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities.” One of the provisions of ASU No. 2016-01 was to supersede the guidance to classify equity securities with readily determinable fair value into different categories (that is, trading or available-for-sale) and require equity securities to be measured
We record all derivative financial instrument contracts at fair value within our consolidated balance sheets except for normal purchase and normal sale transactions that are expected to result in physical delivery. For these transactions, 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.

We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value recognized throughof 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 consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements and are reported within cost of sales on the consolidated statements of operations, along with related settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net income. As a resultunbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the adoption, we recorded a cumulative effect adjustmentresulting contractual portfolio are certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of $1.6 million, movingcrude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the unrealizedrisk of loss from accumulatednonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Cost of Sales

We include all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory, prior to delivery to our customers, in cost of sales. Cost of sales excludes depreciation of our property, plant and equipment.

Depreciation and Amortization

Depreciation and amortization in our consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other comprehensive income to limited partners’ equity.

Note 3—Income (Loss) Per Common Unit

The following table presents our calculation of basic and diluted weighted average common units outstandingthan debt issuance costs, for which the periods indicated:amortization is recorded
F-10
  Year Ended March 31,
  2019 2018 2017
Weighted average common units outstanding during the period:      
Common units - Basic 123,017,064
 120,991,340
 108,091,486
Effect of Dilutive Securities:      
Performance awards 
 
 173,087
Warrants 
 
 3,586,048
Common units - Diluted 123,017,064
 120,991,340
 111,850,621

For the year ended March 31, 2019, the Service Awards (as defined herein), warrants and the Class A Preferred Units (as defined herein) were considered antidilutive. Due to the termination of the Performance Award plan (see Note 10), there were no outstanding Performance Awards (as defined herein) as of March 31, 2019. For the year ended March 31, 2018, the Service Awards, Performance Awards, warrants and Class A Preferred Units were considered antidilutive. For the year ended March 31, 2017, the Service Awards and Class A Preferred Units were considered antidilutive.

F-19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


to interest expense and certain contract-based intangible assets, for which the amortization is recorded to either cost of sales or operating expense.

Income Taxes

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

We have certain taxable corporate subsidiaries in the United States and Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2018 to 2021 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income (loss) per common unit is as followstaxes. Under this method, deferred tax assets and liabilities are recognized for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands, except unit and per unit amounts)
(Loss) income from continuing operations $(63,724) $(226,385) $94,802
Less: Continuing operations loss (income) attributable to noncontrolling interests 20,206
 (240) (6,832)
Net (loss) income from continuing operations attributable to NGL Energy Partners LP (43,518) (226,625) 87,970
Less: Distributions to preferred unitholders (1) (111,936) (59,697) (30,142)
Less: Continuing operations net loss (income) allocated to general partner (2) 17
 150
 (183)
Less: Repurchase of warrants (3) 
 (349) 
Net (loss) income from continuing operations allocated to common unitholders $(155,437) $(286,521) $57,645
       
Income from discontinued operations, net of tax $403,119
 $156,780
 $49,072
Less: Discontinued operations loss (income) attributable to redeemable noncontrolling interests 446
 (1,030) 
Less: Discontinued operations income allocated to general partner (2) (404) (155) (49)
Net income from discontinued operations allocated to common unitholders $403,161
 $155,595
 $49,023
       
Net income (loss) allocated to common unitholders $247,724
 $(130,926) $106,668
       
Basic income (loss) per common unit      
(Loss) income from continuing operations $(1.26) $(2.37) $0.53
Income from discontinued operations, net of tax $3.28
 $1.29
 $0.45
Net income (loss) $2.01
 $(1.08) $0.99
Diluted income (loss) per common unit      
(Loss) income from continuing operations $(1.26) $(2.37) $0.52
Income from discontinued operations, net of tax $3.28
 $1.29
 $0.44
Net income (loss) $2.01
 $(1.08) $0.95
Basic weighted average common units outstanding 123,017,064
 120,991,340
 108,091,486
Diluted weighted average common units outstanding 123,017,064
 120,991,340
 111,850,621
(1)This amount includes the distribution to preferred unitholders as well as the accretion for the beneficial conversion, as discussed further in Note 10.
(2)Net (income) loss allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights.
(3)This amount represents the excess of the repurchase price over the fair value of the warrants, as discussed further in Note 10.

future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.
Note 4—Acquisitions

A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our initial public offering.
The following summarizes
We have a deferred tax liability of $43.5 million and $45.8 million at March 31, 2022 and 2021, respectively, as a result of acquiring corporations in connection with certain of our acquisitions, which is included within other noncurrent liabilities in our 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 year ended March 31, 2019:2022 was $1.2 million with an effective tax rate of 11.3%. The deferred tax benefit recorded during the year ended March 31, 2021 was $4.7 million with an effective tax rate of 39.7%.

Water Pipeline Company

On April 24, 2018, we acquired the remaining 18.375% interest in NGL Water Pipelines, LLC operatingWe evaluate uncertain tax positions for recognition and measurement in the Delaware Basin portionconsolidated 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 Permian Basinposition. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in West Texas for total considerationthe consolidated financial statements. We had no uncertain tax positions that required recognition in our consolidated financial statements at March 31, 2022 or 2021.

Cash and Cash Equivalents

Management considers all highly liquid investments with a maturity of approximately $4.0 million. The acquisitionthree months or less, when purchased, to be cash equivalents. We place our cash and cash equivalents with financial institutions that are insured by the Federal Deposit Insurance Corporation; however, we maintain deposits in banks which exceed the amount of deposit insurance available. Management routinely assesses the financial condition of the remaining interest wasinstitutions and believes that any possible credit loss would be minimal.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. See Note 16 for a further discussion of our allowance for expected credit losses.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

CITGO Petroleum Corporation accounted for as an equity transaction, no gain or loss was recorded, and12.8% of our consolidated revenues for the carrying valueyear ended March 31, 2022. The majority of the noncontrolling interest was adjustedrevenue for this customer pertains to reflect the change in ownership interest of the subsidiary. As of the date of the transaction, the 18.375% interest had a carrying value of $3.9 million.


our Crude Oil Logistics segment activities, and sales to this customer
F-20
F-11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Saltwater Water Solutions Facilities

Duringoccur mainly out of our crude oil terminal in Cushing, Oklahoma. We did not have any customers that represented over 10% of consolidated revenues for the yearyears ended March 31, 2019,2021 and 2020.

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 acquired six saltwater disposal facilities (including 15 saltwater disposal wells)consider fixed-price forward commitments.

Inventories consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Crude oil$135,485 $64,916 
Propane43,971 45,521 
Butane33,144 19,189 
Biodiesel20,474 16,169 
Diesel3,504 2,252 
Ethanol3,503 3,056 
Other11,196 7,364 
Total$251,277 $158,467 

Investments in Unconsolidated Entities

Investments we do not control, but can exercise significant influence over, are accounted for total considerationusing the equity method of approximately $116.1 million.

As partaccounting. Investments in partnerships and limited liability companies, unless our investment is considered to be minor, and investments in unincorporated joint ventures are also accounted for using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these acquisitions,entities on our consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the net assets of the investee. We consider distributions received from unconsolidated entities which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in our consolidated statements of cash flows. We consider distributions received from unconsolidated entities in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in our consolidated statements of cash flows.

At March 31, 2022, cumulative equity earnings and cumulative distributions of our unconsolidated entities since they were acquired were $6.5 million and $9.4 million, respectively.

F-12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Our investments in unconsolidated entities consist of the following at the dates indicated:
March 31,
EntitySegmentOwnership Interest20222021
(in thousands)
Water services and land companyWater Solutions50%$15,714 $15,832 
Water services and land companyWater Solutions10%2,863 3,254 
Water services and land companyWater Solutions50%2,210 2,284 
Aircraft company (1)Corporate and Other50%538 748 
Water services companyWater Solutions50%409 424 
Natural gas liquids terminal companyLiquids Logistics50%163 177 
Total$21,897 $22,719 
(1)    This is an investment with a related party. See Note 12 for a further discussion.

Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Linefill (1)$28,065 $28,110 
Minimum shipping fees - pipeline commitments (2)8,899 13,171 
Loan receivable (3)3,147 2,962 
Other5,691 6,490 
Total$45,802 $50,733 
(1)    Represents minimum volumes of product we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At March 31, 2022 and 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). During the three months ended March 31, 2020, we recorded customer relationship, favorablean impairment of $7.7 million primarily due to adjusting the cost basis of pipeline linefill to the market price of propane as of March 31, 2020.
(2)    Represents the noncurrent portion of minimum shipping fees paid in excess of volumes shipped, or deficiency credits, for a contract and non-compete agreement intangible assets whereby we estimatedwith a crude oil pipeline operator. This amount can be recovered when volumes shipped exceed the value of these intangible assets using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted)minimum monthly volume commitment (see Note 8). The measurement is based on the value indicated by current market expectations about those future amounts.

The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are accounting for these transactions as business combinations. The following table summarizes the transaction close date preliminary estimates of the fair values for the assets acquired and liabilities assumed (in thousands):
Property, plant and equipment$36,590
Goodwill50,619
Intangible assets29,287
Current liabilities(10)
Other noncurrent liabilities(410)
Fair value of net assets acquired$116,076


As of March 31, 2019,2022, the allocationdeficiency credit was $13.2 million, of which $4.3 million is recorded within prepaid expenses and other current assets in our consolidated balance sheet.
(3)    Represents the noncurrent portion of a loan receivable, net of an allowance for an expected credit loss, with a former related party.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the purchase price is considered preliminary as we are continuing to gather additional information to finalizefollowing at the fair values of thedates indicated:
March 31,
20222021
(in thousands)
Accrued interest$56,104 $56,299 
Derivative liabilities27,108 21,562 
Accrued compensation and benefits18,417 41,456 
Excise and other tax liabilities10,451 10,970 
Product exchange liabilities853 1,188 
Other27,786 38,925 
Total$140,719 $170,400 
Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included within loss on disposal or impairment of
F-13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

assets, net. We compute depreciation expense of our property, plant and equipment using the straight-line method over the estimated useful lives of the assets (see Note 4).

Intangible Assets

Our intangible assets.assets include contracts and arrangements acquired in business combinations, including customer relationships, customer commitments, pipeline capacity rights, rights-of-way and easements, water rights, executory contracts and other agreements, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs associated with the ABL Facility (as defined herein) and the Sawtooth Caverns, LLC (“Sawtooth”) credit agreement. We amortize the majority of our intangible assets on a straight-line basis over the estimated useful lives of the assets (see Note 6). We amortize debt issuance costs over the terms of the related debt using a method that approximates the effective interest method.

Impairment of Long-Lived Assets

We evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. If the carrying value is not recoverable, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value. When we cease to use an acquired trade name, we test the trade name for impairment using the relief from royalty method and we begin amortizing the trade name over its estimated useful life as a defensive asset. See Note 4 and Note 6 for a further discussion of long-lived asset impairments recognized in the consolidated statements of operations.

We evaluate our investments in unconsolidated entities for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the fair value of such investment may have experienced a decline to less than its carrying value and the decline is other than temporary.

Goodwill

Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expandBusiness combinations are accounted for using the number of our disposal sites in an oilfield production basin currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in this oilfield production basin.“acquisition method”. We expect that all of theour goodwill will beat March 31, 2022 is deductible for federal income tax purposes.

The operationsGoodwill and indefinite-lived intangible assets are not amortized, but instead are evaluated for impairment at least annually. We perform our annual assessment of these water solutions facilities have been includedimpairment on January 1 of our fiscal year, and more frequently if circumstances warrant.

For purposes of the goodwill impairment assessment, assets are grouped into “reporting units.” A reporting unit is either an operating segment or a component of an operating segment, depending on how similar the components of the operating segment are to each other in our consolidated statementterms of operations since their acquisition date. Our consolidated statementoperational and economic characteristics. For each reporting unit, we perform a qualitative assessment of operations forrelevant events and circumstances about the year ended March 31, 2019 includes revenueslikelihood of $12.6 milliongoodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying value, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, goodwill is considered to be impaired and operating income of $4.9 million that were generatedthe goodwill balance is reduced by the operations of these water solutions facilities. We incurred $0.2 million of transaction costs related to these acquisitions duringdifference between the year ended March 31, 2019. These amounts are recorded within generalfair value and administrative expenses in our consolidated statement of operations.

During the year ended March 31, 2019, we also acquired seven saltwater disposal wells for total consideration of $35.2 million, which we are accounting for as acquisitions of assets. The consideration paid for this transaction was allocated primarily to property, plant and equipment.

Freshwater Water Solutions Facilities

During the year ended March 31, 2019, we acquired a ranch and four freshwater facilities (including 27 freshwater wells) and a right-of-way that can be used for pipelines for total consideration of approximately $77.2 million.

As part of these acquisitions, we recorded water rights, customer relationship, favorable contract and non-compete agreement intangible assets, whereby we estimated thecarrying value of these intangible assets using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

reporting unit.
A book/tax difference was created as part
Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of one ofthe analysis. The estimates and assumptions we used in the annual goodwill impairment assessment included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these acquisitions and as a result, we have recorded a preliminary noncurrent deferred tax liability of $16.3 million (see estimates. See Note 25 for a further discussion).discussion and analysis of our goodwill impairment assessment.


Product Exchanges
We recorded contingent consideration liabilities
Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets and within accrued expenses and other payables and other noncurrent liabilities in our consolidated balance sheet related to future royalty payments due tosheets. We estimate the seller. We estimated the contingent consideration for one liabilityvalue of product exchange assets and liabilities based on the contracted royalty rate, which is a flat rate per barrel, multiplied byweighted-average cost basis of the expected volumes of freshwater sold. We estimated the contingent consideration for the other liability basedinventory we have delivered or will deliver on the contracted royalty rate, which is a flat rate per barrel, multiplied by the expected third party volumes to be transported on the pipeline for the

exchange, plus or minus location differentials.
F-21
F-14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


expected useful lifeNoncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the rights-of-way. These amounts were then discounted to present value usingsubsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrolling interests are reported as a component of equity, unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in our weighted average costconsolidated balance sheet.

Acquisitions

To determine if a transaction should be accounted for as a business combination or an acquisition of capital plus a premium representativeassets, we first calculate the relative fair values of the uncertainty associated with the expected volumes. Asassets acquired. If substantially all of the acquisition date,relative fair value is concentrated in a single asset or group of similar assets, or if not but the transaction does not include a significant process (does not meet the definition of a business), we recorded a contingent liability of $2.7 million.

We assumed land leases with a royalty componentrecord the transaction as part of thean acquisition of certainassets. For acquisitions of these facilities. The acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions atassets, the acquisition date be recorded as liabilities in the acquisition accounting. We recorded a liability within other noncurrent liabilities of $0.5 million related to these leases due to the royalty terms being deemed unfavorable. We will amortize this liabilitypurchase price is allocated based on the volumes processed by the facilities.

The agreements for these acquisitions contemplate post-closing payments for certain working capital items. Werelative fair values and goodwill is not recorded. All other transactions are accounting for these transactionsrecorded as business combinations. The following table summarizes the transaction close date preliminary estimates of the fair values forWe record the assets acquired and liabilities assumed (in thousands):
Property, plant and equipment$7,123
Goodwill23,570
Intangible assets64,015
Investments in unconsolidated entities2,060
Current liabilities(276)
Other noncurrent liabilities(19,288)
Fair value of net assets acquired$77,204


As of March 31, 2019,in a business combination at their acquisition date fair values. For a business combination, the allocationexcess of the purchase price over the net fair value of acquired assets and assumed liabilities is considered preliminaryrecorded as we are continuinggoodwill, which is not amortized but instead is evaluated for impairment at least annually (as described above).

Pursuant to gather additionalGAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to finalize the fair values of land, other property, plantidentify and equipment, intangible assets, including customer relationships, and the investment in the unconsolidated entity. We are also engaging a third party valuation firm to assist us in this effort. The noncurrent deferred tax liability is also considered preliminary and will be finalized oncemeasure the fair value of the assets acquired has been finalized.and liabilities assumed in a business combination.

Goodwill representsReclassifications

We have reclassified certain prior period financial statement information to be consistent with the excessclassification 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 November 2020, the consideration paidSecurities and Exchange Commission (“SEC”) issued a Final Rule, “Management’s Discussion and Analysis, Selected Financial Data, and Supplementary Financial Information”, to modernize, simplify and enhance certain financial disclosure requirements in Regulation S-K. The Final Rule eliminates Regulation S-K, Item 301. Selected Financial Data, streamlines the requirements in Item 302. Supplementary Financial Information, and updates certain requirements in Item 303. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The guidance is effective for fiscal periods ending on or after August 9, 2021, although early adoption is permitted if an entity complies with an amended Item in its entirety. Effective March 31, 2021, we adopted a portion of this guidance by electing to comply with guidance related to Item 301, which eliminated the acquired businesses overSelected Financial Data, and Item 302, which allowed us to eliminate the fair value ofQuarterly Financial Data from the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand our service offerings in an oilfield production basin currently serviced by us, thereby enhancing our competitive position as a provider of disposal and other services in this oilfield production basin. We expect that all of the goodwill will be deductible for federal income tax purposes.

The operations of these water solutions facilities have been included in our consolidated statement of operations since their acquisition date. Our consolidated statement of operationsAnnual Report on Form 10-K for the year ended March 31, 2019 includes revenues2021. Effective March 31, 2022, we adopted the guidance to comply with the requirements in Item 303. Management’s Discussion and Analysis of $2.0 millionFinancial Condition and Results of Operations.

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 operating lossEntity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of $1.1 millionthe three models in Accounting Standards Codification (“ASC”) 470-20 that were generatedrequire 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. We adopted this guidance on April 1, 2022 using the modified retrospective method. Under our Class D Preferred Unit (as defined in Note 9) 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 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. Other than the potential impact to our future earnings per unit calculations, the adoption of this guidance did not impact our financial position, results of operations of these water solutions facilities. We incurred $3.7 million of transaction costsor cash flows related to these acquisitions during the year ended March 31, 2019. These amounts are recorded within general and administrative expenses in our consolidated statement of operations.any debt or preferred units issued prior to adoption.

During the year ended March 31, 2019, we also acquired an additional ranch (including 18 freshwater wells) for total consideration of $28.4 million, which we are accounting for as an acquisition of assets. The consideration paid for this transaction was allocated to land and intangible assets.

Natural Gas Liquids Terminal Business

In March 2019, we completed the acquisition of the natural gas liquids terminal business of DCP Midstream, LP. The acquisition consisted of five propane rail terminals, located in the Eastern United States, a 50% ownership interest in an additional rail terminal, located in the state of Maine, and an import/export terminal located in Chesapeake, Virginia for total consideration of approximately $103.4 million. The import/export terminal has the capability to load and unload ships ranging in size from handy-sized vessels up to very large gas carriers. These terminals complement our existing natural gas liquids portfolio and also create additional opportunities for new and existing customers to supply their business.

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


F-22
F-15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


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 agreementASU 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 acquisition contemplates post-closing payments for certain working capital items.ASU. On April 13, 2022, the ABL Facility (as defined herein) was amended to replace the LIBOR benchmark with the SOFR (as defined herein) benchmark (as discussed further in Note 7). We are accounting forcontinuing to evaluate the effect that this transaction as a business combination. guidance will have on our financial position, results of operations and cash flows.

Note 3—Loss Per Common Unit

The following table summarizespresents our calculation of basic and diluted weighted average common units outstanding for the transaction close date preliminary estimatesperiods indicated:
Year Ended March 31,
202220212020
Weighted average common units outstanding during the period:
Common units - Basic129,840,234 128,980,823 127,411,908 
Common units - Diluted129,840,234 128,980,823 127,411,908 

For the years ended March 31, 2022, 2021 and 2020, all potential common units or convertible securities were considered antidilutive.

Our loss per common unit is as follows for the periods indicated:
Year Ended March 31,
202220212020
(in thousands, except unit and per unit amounts)
Loss from continuing operations$(184,101)$(637,418)$(180,545)
Less: Continuing operations (income) loss attributable to noncontrolling interests(655)(632)1,773 
Net loss from continuing operations attributable to NGL Energy Partners LP(184,756)(638,050)(178,772)
Less: Distributions to preferred unitholders (1)(2)(104,163)(93,364)(188,734)
Less: Continuing operations net loss allocated to general partner (3)289 731 260 
Net loss from continuing operations allocated to common unitholders$(288,630)$(730,683)$(367,246)
Loss from discontinued operations, net of tax$— $(1,769)$(218,235)
Less: Discontinued operations net loss allocated to general partner (3)— 218 
Net loss from discontinued operations allocated to common unitholders$— $(1,767)$(218,017)
Net loss allocated to common unitholders$(288,630)$(732,450)$(585,263)
Basic loss per common unit
Loss from continuing operations$(2.22)$(5.67)$(2.88)
Loss from discontinued operations, net of tax$— $(0.01)$(1.71)
Net loss$(2.22)$(5.68)$(4.59)
Diluted loss per common unit
Loss from continuing operations$(2.22)$(5.67)$(2.88)
Loss from discontinued operations, net of tax$— $(0.01)$(1.71)
Net loss$(2.22)$(5.68)$(4.59)
Basic weighted average common units outstanding129,840,234 128,980,823 127,411,908 
Diluted weighted average common units outstanding129,840,234 128,980,823 127,411,908 
(1)This amount includes distributions to preferred unitholders. The final accretion for the beneficial conversion of the fair values for the assets acquired10.75% Class A Preferred Units (as defined herein) and liabilities assumed (in thousands):
Inventories$15,370
Other current assets667
Property, plant and equipment42,413
Goodwill20,472
Intangible assets26,900
Investments in unconsolidated entities204
Current liabilities(2,128)
Other noncurrent liabilities(524)
Fair value of net assets acquired$103,374


As of March 31, 2019, the allocation of the purchase price is considered preliminary as we are continuing to gather additional information to finalize the fair values of the property, plant and equipment, intangible assets and the investment in the unconsolidated entity.

Goodwill represents the excess of the consideration paid for the acquired businesses10.75% Class A Preferred Units repurchase price over the faircarrying value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand the number of our natural gas liquids terminalsunits, as discussed further in an area currently serviced by us, thereby enhancing our competitive position as a provider of terminaling services in this area. We expect that all of the goodwill will be deductible for federal income tax purposes.

The operations of these natural gas liquids terminals have beenNote 9, are included in our consolidated statement of operations since their acquisition date. Our consolidated statement of operationsthe year ended March 31, 2020.
(2)    Includes cumulative distributions for the year ended March 31, 2019 includes revenues of $22.7 million2022 and operating income of $2.4 million that were generated byfor the operations of these natural gas liquids terminals. We incurred $0.5 million of transaction costs related to this acquisition during the yearquarter ended March 31, 2019. These amounts are recorded within general and administrative expenses in our consolidated statement of operations.

Refined Products Terminals

In January 2019, we completed the acquisition of two refined products terminals located in Georgia2021 which were earned but not declared or paid (see Note 9 for total consideration of approximately $16.3 million.

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

The agreement for this acquisition contemplates post-closing payments for certain working capital items. We are accounting for this transaction as a business combination. The following table summarizes the transaction close date preliminary estimatesfurther discussion of the fair values for the assets acquiredsuspension of common unit and liabilities assumed (in thousands):preferred unit distributions).
Inventories$327
Other current assets85
Property, plant and equipment9,986
Goodwill1,328
Intangible assets4,600
Current liabilities(4)
Fair value of net assets acquired$16,322
F-16


As of March 31, 2019, the allocation of the purchase price is considered preliminary as we are continuing to gather additional information to finalize the fair values of the property, plant and equipment and intangible assets.

Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand the number of our refined

F-23

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


products terminals in an area currently serviced by us, thereby enhancing our competitive position as a provider of terminaling services in this area. We expect that all of the goodwill will be deductible for federal income tax purposes.

The operations of these refined products terminals have been included in our consolidated statement of operations since their acquisition date. Our consolidated statement of operations for the year ended March 31, 2019 includes revenues of $0.3 million and an operating(3)    Net loss of $0.1 million that were generated by the operations of these refined products terminals. We incurred $0.1 million of transaction costs related to this acquisition during the year ended March 31, 2019. These amounts are recorded within general and administrative expenses in our consolidated statement of operations.

Retail Propane Businesses

During the three months ended June 30, 2018, we acquired three retail propane businesses for total consideration of approximately $19.1 million. We accounted for these transactions as business combinations.

On July 9, 2018, and in conjunction with the sale of the Retail Propane segment (see Note 1), we acquired the remaining 40% interest in Atlantic Propane, LLC, which was part of our Retail Propane segment, for total consideration of approximately $12.8 million. The acquisition of the remaining interest was accounted for as an equity transaction, no gain or loss was recorded, and the carrying value of the noncontrolling interest was adjusted to reflect the change in ownership interest of the subsidiary. Atlantic Propane, LLC was included in the sale to Superior (see Note 1).

The assets and liabilities of these retail propane transactions were included in the sale of virtually all of our remaining Retail Propane segment on July 10, 2018 and the operations have been classified as discontinued (see Note 17).

The following summarizes the status of the preliminary purchase price allocation of acquisitions prior to April 1, 2018:

Retail Propane Businesses

During the three months ended June 30, 2018, we completed the acquisition accounting for the remaining four retail propane businesses, which were part of the sale of virtually all of our Retail Propane segment (see Note 17). The assets and liabilities are included in current assets and current liabilities held for sale in our March 31, 2018 consolidated balance sheet (see Note 17). There were no material adjustmentsallocated to the fair valuegeneral partner includes distributions to which it is entitled as the holder of assets acquired and liabilities assumed during the three months ended June 30, 2018.incentive distribution rights.



F-24

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Note 54—Property, Plant and Equipment

Our property, plant and equipment consists of the following at the dates indicated:
EstimatedMarch 31,EstimatedMarch 31,
DescriptionUseful Lives2019 2018DescriptionUseful Lives20222021
(in years)(in thousands)(in years)(in thousands)
Natural gas liquids terminal and storage assets2-30$280,106
 $238,487
Natural gas liquids terminal and storage assets2-30$173,199 $319,554 
Pipeline and related facilities30-40243,799
 243,616
Pipeline and related facilities30-40265,643 264,405 
Refined products terminal assets and equipment15-2515,187
 6,736
Vehicles and railcars3-25124,948
 121,159
Vehicles and railcars3-2593,126 126,088 
Water treatment facilities and equipment3-30704,666
 601,139
Water treatment facilities and equipment3-302,040,687 1,930,437 
Crude oil tanks and related equipment2-30225,476
 218,588
Crude oil tanks and related equipment2-30236,805 238,924 
Barges and towboats5-30103,735
 92,712
Barges and towboats5-30138,778 137,386 
Information technology equipment3-733,082
 30,749
Information technology equipment3-748,664 50,220 
Buildings and leasehold improvements3-40144,567
 147,442
Buildings and leasehold improvements3-40151,071 165,679 
Land 63,368
 51,816
Land100,038 100,352 
Tank bottoms and line fill (1) 20,071
 20,118
Tank bottoms and linefill (1)Tank bottoms and linefill (1)30,443 20,237 
Other3-2015,018
 11,794
Other3-2015,252 15,054 
Construction in progress 290,832
 77,596
Construction in progress55,690 114,796 
 2,264,855
 1,861,952
3,349,396 3,483,132 
Accumulated depreciation (420,362) (343,345)Accumulated depreciation(887,006)(776,279)
Net property, plant and equipment $1,844,493
 $1,518,607
Net property, plant and equipment$2,462,390 $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.

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

Amounts in the table above do not include property, plant and equipment and accumulated depreciation related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Depreciation expense$203,783 $190,204 $132,791 
Capitalized interest expense$916 $2,778 $650 
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Depreciation expense $102,314
 $100,576
 $90,474
Capitalized interest expense $482
 $182
 $6,887


Amounts in the table above do not include depreciation expense and capitalized interest related to our former Retail Propane segment,TransMontaigne Product Services, LLC (“TPSL”), as these amounts have been classified withinas discontinued operations within our consolidated statementsstatement of operations for the year ended March 31, 2020 (see Note 17)18).

F-25

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



We record (gains) losses from the sales of property, plant and equipment and any write-downs in value due to impairment within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations. The following table summarizes (gains) losses on the disposal or impairment of property, plant and equipment by segment for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Water Solutions$28,068 $36,492 $22,491 
Crude Oil Logistics(3,194)1,766 36 
Liquids Logistics11,750 3,350 (30)
Corporate and Other— 228 — 
Total$36,624 $41,836 $22,497 
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Crude Oil Logistics (1) $3,489
 $(3,144) $8,124
Water Solutions 3,067
 8,117
 7,169
Liquids 993
 639
 92
Refined Products and Renewables 
 15
 91
Corporate 
 8
 (1)
Total $7,549
 $5,635
 $15,475

F-17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

(1)Amount for the year ended March 31, 2018 primarily relates to a gain related to the sale of excess pipe, partially offset by losses from the disposal of certain assets and the write-down of other assets. Amount for the year ended March 31, 2017 primarily relates to losses from the sale of certain assets, including excess pipe.

During the year ended March 31, 2022, the following transactions were recorded:

A net loss of $22.3 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets in our Water Solutions segment.
A loss of $11.8 million on the sale of a natural gas liquids terminals in our Liquids Logistics segment.
An impairment charge of $5.8 million to write down the value of an inactive saltwater disposal facility that we do not expect to bring back online as a result of suspended operations from increased seismic activity in our Water Solutions segment.
A loss of $2.2 million from the retirement of certain crude oil terminal assets damaged as part of Hurricane Ida in our Crude Oil Logistics segment.
A gain of $5.5 million on the sale of our trucking assets in our Crude Oil Logistics segment.

During the year ended March 31, 2021, the following transactions were recorded within our Water Solutions segment:

An impairment charge of $30.6 million to write down the value of an asset group due to a decline in producer activity, resulting in lower disposal volumes. See Note 6—Goodwill for a discussion of the impairment of intangible assets within this asset group.
An impairment charge of $11.9 million to write down the value of certain inactive saltwater disposal facilities that we do not expect to bring back online.
A net loss of $6.7 million related to write-down or write off of certain assets, including facilities damaged by lightning strikes and abandoned projects, and the sale of certain other miscellaneous assets.
A gain of $12.8 million related to the sale of certain permits, land and a saltwater disposal facility (see Note 17).

During the year ended March 31, 2020, the following transactions were recorded within our Water Solutions segment:

An impairment charge of $13.5 million to write down the value of certain inactive saltwater disposal facilities.
A net loss of $9.0 million related to write-down or write off of certain assets, including abandoned projects, and the sale of certain other miscellaneous assets.

Note 5—Goodwill

The following table summarizes changes in goodwill by segment for the periods indicated (in thousands):period indicated:
Water
Solutions
Crude Oil
Logistics
Liquids
Logistics
Total
(in thousands)
Balances at March 31, 2020$294,658 $579,846 $119,083 $993,587 
Revisions to acquisition accounting(11,348)— — (11,348)
Impairment— (237,800)— (237,800)
Balances at March 31, 2021$283,310 $342,046 $119,083 $744,439 
Balances at March 31, 2022$283,310 $342,046 $119,083 $744,439 
 Crude Oil
Logistics
 Water
Solutions
 Liquids Refined
Products and
Renewables
 Total
 (in thousands)
Balances at March 31, 2017$579,846
 $424,270
 $266,046
 $51,127
 $1,321,289
Revisions to acquisition accounting
 195
 
 
 195
Impairment
 
 (116,877) 
 (116,877)
Balances at March 31, 2018579,846
 424,465
 149,169
 51,127
 1,204,607
Acquisitions (Note 4)
 74,189
 20,472
 1,328
 95,989
Disposals (Note 16)
 (88,515) 
 
 (88,515)
Impairment
 
 (66,220) 
 (66,220)
Balances at March 31, 2019$579,846
 $410,139
 $103,421
 $52,455
 $1,145,861


Fiscal Year 20192022 Goodwill Impairment Assessment

We performed a qualitative assessment as of January 1, 2022 to determine whether it was more likely than not that the fair value of each reporting unit was greater than the carrying value of the reporting unit. Based on these qualitative assessments, we determined that the fair value of each of our reporting units was more likely than not greater than the carrying value of the reporting units as of January 1, 2022, with the exception of our Crude Oil Logistics reporting unit. See below for a further discussion of the testing.

Due to the continued decrease in demand for natural gas liquid storage and the resulting decline in revenues and earnings as compared to actual and projectedlower than expected operating results, we testedit was decided that the goodwill within our natural gas liquids salt cavern storagethe Crude Oil Logistics reporting unit (“Sawtooth reporting unit”), which is part of our Liquids segment,should be tested for impairment atas of January 1, 2019.2022. We estimated the fair value of our Sawtooththe Crude Oil Logistics reporting unit
F-18

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

based on the income approach, also known as the discounted cash flow method, which utilizes the present value of future expected cash flows to estimate the fair value. The future cash flows of our Sawtooththe Crude Oil Logistics reporting unit were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) expected storage volumes, which are assumed to increasethe crude oil price environment as reflected in the coming years due to increased production of natural gas liquids, (ii) expected propane and butanecrude oil forward prices (iii) expected rental fees and (iv) the addition of storing refined products (which we acquired as part of the saletest date, (ii) volumes based on historical information and estimates of future drilling and completion activity, as well as expectations for future demand recovery and (iii) estimated fixed and variable costs. The discounted cash flows for the Crude Oil Logistics reporting unit were based on five years of projected cash flows and we applied a portiondiscount rate and terminal multiple that we believe would be applied by a theoretical market participant in similar market transactions. Based on this test, we concluded that the fair value of the Crude Oil Logistics reporting unit exceeded its carrying value by approximately 12.0%.

Fiscal Year 2021 Goodwill Impairment Assessment

We performed a qualitative assessment as of January 1, 2021 to determine whether it was more likely than not that the fair value of each reporting unit was greater than the carrying value of the reporting unit (see Note 16). We assumedunit. Based on these qualitative assessments, we determined that commodity prices would be flat through the durationfair value of each of our reporting units was more likely than not greater than the carrying value of the model and an average increasereporting units as of approximately 7% increase in rental fees per year starting in April 2020, and held such prices and fees flat for periods in our model beyond our 2024 fiscal year. For expenses, we assumed an increase consistentJanuary 1, 2021, with the increaseexception of our Water Solutions reporting unit, and our Crude Oil Logistics reporting unit, which was tested for impairment as of December 31, 2020. See below for a further discussion of the testing.

Due to lower than expected disposal volumes as a result of a slower than expected recovery in storage volumes,oil production in the various basins in which our Water Solutions reporting unit operates and maintenance capitalthe completion of our annual budget process, it was held flat throughoutdecided that the model. The discount rate used ingoodwill within the Water Solutions reporting unit should be tested for impairment as of January 1, 2021. We estimated the fair value of our Water Solutions reporting unit based on the income approach, also known as the discounted cash flow method, was a risk adjusted weighted average costwhich utilizes the present value of capital calculatedfuture expected cash flows to estimate the fair value. The future cash flows of the Water Solutions reporting unit were projected based upon estimates as of January 1, 2019the test date of approximately 13.1%.future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) the crude oil price environment as reflected in crude oil forward prices as of the test date, (ii) disposal volumes based on historical information and estimates of future drilling and completion activity, as well as expectations for future demand recovery and (iii) estimated fixed and variable costs. The discounted cash flow results indicatedflows for the Water Solutions reporting unit were based on five years of projected cash flows and we applied a discount rate and terminal multiple that we believe would be applied by a theoretical market participant in similar market transactions. Based on this test, we concluded that the estimated fair value of the Water Solutions reporting unit exceeded its carrying value by approximately 3.0%.

As discussed in Note 17, in December 2020, we reached a settlement in the Extraction Oil & Gas, Inc.(“Extraction”) bankruptcy case, which is expected to result in decreases in future cash flows for certain of our Sawtoothassets. Based on this aforementioned event, we concluded that a triggering event occurred, which required us to perform a quantitative impairment test as of December 31, 2020 for our Crude Oil Logistics reporting unit. We estimated the fair value of the Crude Oil Logistics reporting unit based on the income approach, also known as the discounted cash flow method, which utilizes the present value of future expected cash flows to estimate the fair value. The future cash flows of the Crude Oil Logistics reporting unit were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) the crude oil price environment as reflected in crude oil forward prices as of the test date, (ii) volumes based on historical information and estimates of future drilling and completion activity, as well as expectations for future demand recovery and (iii) estimated fixed and variable costs. The discounted cash flows for the Crude Oil Logistics reporting unit were based on five years of projected cash flows and we applied a discount rate and terminal multiple that we believe would be applied by a theoretical market participant in similar market transactions. Based on this test, we concluded that the fair value of the Crude Oil Logistics reporting unit was less than its carrying value by approximately 35.2% at January 1, 2019.17.0%.

During the three months ended December 31, 2020, in our Crude Oil Logistics reporting unit, we recorded a goodwill impairment charge of $237.8 million within loss on disposal or impairment of assets, net in our consolidated statement of operations.

F-26
F-19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Fiscal Year 2020 Goodwill Impairment Assessment

During the three months ended March 31, 2019, we recorded a goodwill impairment charge of $66.2 million, which was a write-off of the remaining goodwill within the Sawtooth reporting unit. The goodwill impairment charge was recorded within loss (gain) on disposal or impairment of assets, net, in our consolidated statement of operations.

We performed a qualitative assessment as of January 1, 20192020 to determine whether it was more likely than not that the fair value of each reporting unit was greater than the carrying value of the reporting unit. Based on these qualitative assessments, we determined that the fair value of each of these reporting units was more likely than not greater than the carrying value of the reporting units other thanas of January 1, 2020.

During the Sawtooth reporting unitmonth of March 2020, our market capitalization declined significantly driven by current macroeconomic conditions including the collapse of oil prices driven by both the decrease in demand caused by the novel strain of coronavirus (COVID-19) pandemic and excess supply, as previously described.

Fiscal Year 2018 Goodwill Impairment Assessment

Due to the decreased demandwell as changing market conditions and expected lower crude oil production in certain regions, resulting in expected decreases in future cash flows for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods, we tested the goodwill within our Sawtooth reporting unit, which is partcertain of our Liquids segment,assets. In addition, the uncertainty related to oil demand continues to have a significant impact on the investment and operating plans of our primary customers. Based on these events, we concluded that a triggering event occurred which required us to perform a quantitative impairment test as of March 31, 2020 for impairment at September 30, 2017.our reporting units. We estimated the fair value of our Sawtooth reporting unitunits based on the income approach, also known as the discounted cash flow method, which utilizes the present value of future expected cash flows to estimate the fair value. The future cash flows of our Sawtooth reporting unitunits were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) expected storagethe crude oil price environment as reflected in crude oil forward prices as of the test date, (ii) volumes which are assumed to increase in the coming years due to increased productionbased on historical information and estimates of natural gas liquids, (ii) expected propanefuture drilling and butane pricescompletion activity, as well as expectations for future demand recovery and (iii) expected rental fees. We assumed a 2% per year increase in commodity pricesestimated fixed and a 4% increase in rental fees per year starting in April 2018, and held such prices and fees flat for periods in our model beyond our 2023 fiscal year. For expenses, we assumed an increase consistent with the increase in storage volumes, and maintenance capital was held flat throughout the model. The discount rate used in our discounted cash flow method was a risk adjusted weighted average cost of capital calculated as of September 30, 2017 of 12%.variable costs. The discounted cash flow results indicatedflows for each reporting unit were based on five years of projected cash flows and we applied discount rates and terminal multiples that we believe would be applied by a theoretical market participant in similar market transactions. Based on these tests, we concluded that the estimatedfair values of each of our reporting units exceeded their carrying values with the exception of our Water Solutions reporting unit, whose fair value of our Sawtooth reporting unit was less than its carrying value by approximately 32% at September 30, 2017.7.3%.

During the three months ended September 30, 2017,March 31, 2020, in our Water Solutions reporting unit, we recorded a goodwill impairment charge of $116.9$250.0 million which was recorded within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations. At September 30, 2017, our Sawtooth reporting unit had a goodwill balance

Note 6—Intangible Assets

Our intangible assets consist of $66.2 million.the following at the dates indicated:

Weighted-
AverageMarch 31, 2022March 31, 2021
DescriptionRemaining Useful LifeGross Carrying
Amount
Accumulated
Amortization
NetGross Carrying
Amount
Accumulated
Amortization
Net
(in years)(in thousands)
Amortizable:
Customer relationships19.4$1,200,919 $(436,837)$764,082 $1,318,638 $(450,639)$867,999 
Customer commitments22.3192,000 (21,120)170,880 192,000 (13,440)178,560 
Pipeline capacity rights21.77,799 (2,167)5,632 7,799 (1,907)5,892 
Rights-of-way and easements31.891,664 (12,201)79,463 90,703 (9,270)81,433 
Water rights17.199,869 (20,404)79,465 100,369 (14,454)85,915 
Executory contracts and other agreements22.520,931 (3,014)17,917 48,709 (21,300)27,409 
Non-compete agreements0.67,000 (6,487)513 12,100 (6,102)5,998 
Debt issuance costs (1)3.922,202 (5,055)17,147 9,558 (406)9,152 
Total amortizable1,642,384 (507,285)1,135,099 1,779,876 (517,518)1,262,358 
Non-amortizable:
Trade names255 — 255 255 — 255 
Total$1,642,639 $(507,285)$1,135,354 $1,780,131 $(517,518)$1,262,613 
In Note 16, we discuss a transaction in which we formed a joint venture which included our Sawtooth salt dome storage facility. As a result of this transaction, we tested the goodwill of our Sawtooth reporting unit, immediately prior
(1)    Includes debt issuance costs related to the closing of this transaction, for impairment. As of March 30, 2018, ourABL Facility (as defined herein) and the Sawtooth reporting unit hadcredit agreement. Debt issuance costs related to fixed-rate notes are reported as a goodwill balance of $66.2 million. Similar to the analysis we performed as of September 30, 2017, as discussed above, we estimated the fair value of our Sawtooth reporting unit based on the income approach, also known as the discounted cash flow method, which utilizes the present value of future expected cash flows to estimate the fair value. The future cash flows of our Sawtooth reporting unit were projected based upon estimates asreduction of the test datecarrying amount of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) expected storage volumes, which are assumed to increase in the coming years due to increased production of natural gas liquids, (ii) expected propane and butane prices and (iii) expected rental fees. We assumed a 2% per year increase in commodity prices and a 4% increase in rental fees per year starting in April 2018, and held such prices and fees flat for periods in our model beyond our 2023 fiscal year. For expenses, we assumed an increase consistent with the increase in storage volumes, and maintenance capital was held flat throughout the model. The discount rate used in our discounted cash flow method was a risk adjusted weighted average cost of capital calculated as of March 30, 2018 of 12.4%. The discounted cash flow results indicated that the estimated fair value of our Sawtooth reporting unit was greater than its carrying value by approximately 2% at March 30, 2018.long-term debt.


Our estimated fair value is predicated upon management’s assumption of the growth in the production of natural gas liquids and the decline in the use of railcars to store natural gas liquids. We used these assumptions to estimate the demand for storage at our facility and the revenue generated by customers reserving capacity at our facility. Due to the current volatility in commodity prices and the excess railcars currently in the market, we believe it is reasonably possible that the need for underground storage we estimate in our model does not materialize, such that our estimate of fair value could change and result in further impairment of the goodwill in our Sawtooth reporting unit.

We performed a qualitative assessment as of January 1, 2018 to determine whether it was more likely than not that the fair value of each reporting unit was greater than the carrying value of the reporting unit. Based on these qualitative

F-27F-20

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


assessments, we determined that the fair value of each of these reporting units was more likely than not greater than the carrying value of the reporting units, other than the Sawtooth reporting unit as previously described.

Fiscal Year 2017 Goodwill Impairment Assessment

We performed a qualitative assessment as of January 1, 2017 to determine whether it was more likely than not that the fair value of each reporting unit was greater than the carrying value of the reporting unit. Based on these qualitative assessments, we determined that the fair value of each of these reporting units was more likely than not greater than the carrying value of the reporting units.

Fiscal Year 2016 Goodwill Impairment Assessment

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

Note 7—Intangible Assets

Our intangible assets consist of the following at the dates indicated:
     March 31, 2019 March 31, 2018
Description
Amortizable
Lives
 
Gross Carrying
Amount
 
Accumulated
Amortization
 Net Gross Carrying
Amount
 Accumulated
Amortization
 Net
 (in years) (in thousands)
Amortizable:               
Customer relationships3-30 $747,432
 $(370,072) $377,360
 $718,763
 $(328,666) $390,097
Customer commitments10   310,000
 (74,917) 235,083
 310,000
 (43,917) 266,083
Pipeline capacity rights30   161,785
 (22,438) 139,347
 161,785
 (17,045) 144,740
Rights-of-way and easements1-40 73,409
 (4,509) 68,900
 63,995
 (3,214) 60,781
Water rights14   64,868
 (3,018) 61,850
 
 
 
Executory contracts and other agreements3-30 47,230
 (17,212) 30,018
 42,919
 (15,424) 27,495
Non-compete agreements2-32 12,723
 (2,570) 10,153
 5,465
 (706) 4,759
Debt issuance costs (1)5   42,345
 (29,521) 12,824
 40,992
 (24,593) 16,399
Total amortizable    1,459,792
 (524,257) 935,535
 1,343,919
 (433,565) 910,354
Non-amortizable:               
Trade names    2,800
 
 2,800
 2,800
 
 2,800
Total    $1,462,592
 $(524,257) $938,335
 $1,346,719
 $(433,565) $913,154

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

Amounts in the table above do not include intangible assets and accumulated amortization related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

The weighted-average remaining amortization period for intangible assets is approximately 13.4 years.


F-28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Write off of Intangible Assets

During the year ended March 31, 2018, we wrote off $1.8 million related to the non-compete agreement which was terminated as part of our acquisition of the remaining interest in NGL Solids Solutions, LLC. In connection with the amendment and restatement of the Credit Agreement (as defined herein) in February 2017, we wrote off $4.5 million of deferredFor intangible assets other than debt issuance costs. Duringcosts, we record (gains) losses from the year ended March 31, 2017, we wrote-off $5.2 million relatedsales of intangible assets and any write-downs in value due to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis. In addition, as a result of terminating the development agreement in the Water Solutions segment in June 2016 (see Note 16), we incurred a loss of $5.8 million to write off the water facility development agreement. The losses for the years ended March 31, 2018 and 2017 are reported within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations. We record the write-off of debt issuance costs within gain (loss) on early extinguishment of liabilities, net in our consolidated statement of operations.

During the year ended March 31, 2022, we recorded the following:

A gain of $1.6 million related to the sale of certain intangible assets in our Water Solutions segment.
A loss of $0.1 million from the write-off of debt issuance costs related to the Sawtooth credit agreement which was paid off and terminated prior to us selling our ownership interest in Sawtooth (see Note 17).

During the year ended March 31, 2021, we recorded the following:

An impairment charge of $145.8 million against the customer commitment intangible asset related to a transportation contract with Extraction that was rejected as part of Extraction’s bankruptcy. See Note 17 for a further discussion of Extraction’s bankruptcy and the impairment of the intangible asset.
An impairment charge of $39.2 million to write down the value of a customer relationship intangible asset as part of the write down in value of a larger asset group (see Note 4).
A $4.5 million write off of the debt issuance costs related to a former revolving credit facility which was repaid and terminated on February 4, 2021 (see Note 7).
An impairment charge of $2.5 million to write down the value of the trade name as part of the write down of a larger asset group (see Note 4).

Amortization expense is as follows for the periods indicated:
Year Ended March 31,
Recorded In202220212020
(in thousands)
Depreciation and amortization$84,937 $127,023 $132,521 
Cost of sales281 307 349 
Interest expense4,779 5,572 5,462 
Operating expenses247 247 286 
Total$90,244 $133,149 $138,618 
  Year Ended March 31,
Recorded In 2019 2018 2017
  (in thousands)
Depreciation and amortization $110,546
 $108,444
 $89,765
Cost of sales 5,619
 6,099
 6,828
Interest expense 4,928
 4,568
 4,471
Total $121,093
 $119,111
 $101,064


Amounts in the table above do not include amortization expense related to our former Retail Propane segment,TPSL, as these amounts have been classified withinas discontinued operations within our consolidated statementsstatement of operations for the year ended March 31, 2020 (see Note 1718).
).

ExpectedThe following table summarizes expected amortization of our intangible assets is as followsat March 31, 2022 (in thousands):
Year Ending March 31, 
2020$122,159
2021109,849
202297,011
202388,991
202482,851
Thereafter434,674
Total$935,535

Year Ending March 31, 
2023$82,380 
202475,663 
202567,445 
202664,639 
202760,233 
Thereafter784,739 
Total$1,135,099 
 

F-21
F-29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Note 7—Long-Term Debt
Note 8
—Long-Term Debt

Our long-term debt consists of the following at the dates indicated:
  March 31, 2019 March 31, 2018
  Face
Amount
 Unamortized
Debt Issuance
Costs (1)
 Book
Value
 Face
Amount
 Unamortized
Debt Issuance
Costs (1)
 Book
Value
  (in thousands)
Revolving credit facility: 

          
Expansion capital borrowings $275,000
 $
 $275,000
 $
 $
 $
Working capital borrowings 896,000
 
 896,000
 969,500
 
 969,500
Senior unsecured notes:     

     

5.125% Notes due 2019 ("2019 Notes") 
 
 
 353,424
 (1,653) 351,771
6.875% Notes due 2021 ("2021 Notes") 
 
 
 367,048
 (4,499) 362,549
7.500% Notes due 2023 ("2023 Notes") 607,323
 (6,916) 600,407
 615,947
 (8,542) 607,405
6.125% Notes due 2025 ("2025 Notes") 389,135
 (5,092) 384,043
 389,135
 (5,951) 383,184
Other long-term debt 5,331
 
 5,331
 5,977
 
 5,977
  2,172,789
 (12,008) 2,160,781
 2,701,031
 (20,645) 2,680,386
Less: Current maturities 648
 
 648
 646
 
 646
Long-term debt $2,172,141
 $(12,008) $2,160,133
 $2,700,385
 $(20,645) $2,679,740
March 31, 2022March 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 $(35,140)$2,014,860 $2,050,000 $(44,246)$2,005,754 
Asset-based revolving credit facility (“ABL Facility”)116,000 — 116,000 4,000 — 4,000 
Senior unsecured notes:
7.500% Notes due 2023 (“2023 Notes”)475,702 (1,873)473,829 555,251 (3,564)551,687 
6.125% Notes due 2025 (“2025 Notes”)380,020 (2,456)377,564 380,020 (3,297)376,723 
7.500% Notes due 2026 (“2026 Notes”)332,402 (3,460)328,942 338,402 (4,378)334,024 
Other long-term debt41,705 (59)41,646 49,095 (70)49,025 
 3,395,829 (42,988)3,352,841 3,376,768 (55,555)3,321,213 
Less: Current maturities2,378 — 2,378 2,183 — 2,183 
Long-term debt$3,393,451 $(42,988)$3,350,463 $3,374,585 $(55,555)$3,319,030 
(1)
(1)    Debt issuance costs related to the Revolving Credit Facility are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.

Amounts in the table above do not include long-term debt related to our former Retail Propane segment, as these amounts have been classified as liabilities held for sale within our March 31, 2018 consolidated balance sheet (see Note 17).

Amortization expense for debt issuance costs related to the ABL Facility and the Sawtooth credit agreement (included in other long-term debt indebt) are reported within intangible assets, rather than as a reduction of the table above was $4.3 million, $6.1 million and $3.3 million during the years ended March 31, 2019, 2018 and 2017.carrying amount of long-term debt.

Expected amortization of debt issuance costs is as follows (in thousands):
Year Ending March 31,  
2020 $2,371
2021 2,367
2022 2,367
2023 2,367
2024 1,744
Thereafter 792
Total $12,008


2026 Senior Secured Notes
Credit Agreement

On February 4, 2021, we closed on our private offering of $2.05 billion of 7.5% 2026 Senior Secured Notes. Interest is payable on February 1 and August 1 of each year, beginning 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”).
We
The 2026 Senior Secured Notes are partysecured by first priority liens in 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 in 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 a $1.765 billion credit agreement (the “Credit Agreement”)make distributions, make loans or advances or transfer assets to the guarantors (including the Partnership); enter into certain transactions with a syndicateour affiliates; designate restricted subsidiaries as unrestricted subsidiaries; and merge, consolidate or transfer or sell all or substantially all of banks. As of March 31, 2019, the Credit Agreement includes a revolving credit facilityour assets. The Indenture specifically restricts our ability to fund working capital needs, which had a capacity of $1.250 billion for cash borrowings and letters of credit (the “Working Capital Facility”), and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $515.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). The Revolving Credit Facility allows us to reallocate amounts between the Expansion Capital Facility and Working Capital Facility. We had letters of credit of $143.4 million on the Working Capital Facility at March 31, 2019. The capacity under the Working Capital Facility may be limited by a “borrowing base”pay distributions until our total leverage ratio (as defined in the Credit Agreement) whichIndenture) for the most recently ended four full fiscal quarters at the time of the distribution is calculated basednot greater than 4.75 to 1.00. These covenants are subject to a number of important exceptions and qualifications.

We have an option to redeem all or a portion of the 2026 Senior Secured Notes at any time on or after February 1, 2023 at fixed redemption prices contained within the Indenture. Prior to such time, we, at our option, may redeem up to 40% of the aggregate principal amount of the 2026 Senior Secured Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price specified in the Indenture. In addition, before February 1, 2023, we may redeem some or all of the 2026 Senior Secured Notes at a redemption price equal to 100% of the aggregate principal amount of the 2026 Senior Secured Notes redeemed, plus the applicable premium as specified in the Indenture and accrued and unpaid interest, if any, to, but not including, the redemption date. If we experience certain kinds of change of control triggering events, we will be required to offer to repurchase the 2026 Senior Secured Notes at 101% of the aggregate principal amount of the 2026 Senior Secured Notes repurchased plus accrued and unpaid interest on the value2026 Senior Secured Notes repurchased to, but not including, the date of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on October 5, 2021. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we

purchase.
F-30
F-22

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


enter into certain transactionsCompliance

At March 31, 2022, we were in compliance with the covenants under the 2026 Senior Secured Notes indenture.

ABL Facility

On February 4, 2021, we closed on our ABL Facility that is subject to sell assets or obtain new borrowings.a borrowing base, which includes a sub-limit for letters of credit. The Credit Agreementinitial commitments totaled $500.0 million and the sub-limit for letters of credit was $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 all of our other assets. At March 31, 2022, $116.0 million had been borrowed under the ABL Facility and we had letters of credit outstanding of approximately $155.1 million.

The ABL Facility is scheduled to mature at the earliest of (a) February 4, 2026 or (b) 91 days prior to the earliest 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) a LIBOR-based rate (with such customary provisions under the ABL Facility providing for the replacement of LIBOR with any successor rate such rate having been determined to be a SOFR-base rate (as defined herein) or (ii) an alternate base rate, in each case plus an applicable borrowing margin based on our fixed charge coverage ratio (as defined in the ABL Facility). The applicable margin for alternate base rate loans varies from 1.50% to 2.00% and the applicable margin for LIBOR/SOFR-based loans varies from 2.50% to 3.00%. In addition, a commitment fee will be charged and payable quarterly in arrears based on the average daily unused portion of the revolving commitments under the ABL Facility. Such commitment fee will be 0.50% per year, subject to a reduction to 0.375% in the event our fixed charge coverage ratio is greater than or equal to 1.75 to 1.00.

At March 31, 2019,2022, the borrowings under the Credit AgreementABL Facility had a weighted average interest rate of 4.39%,4.64% calculated as the weighted average LIBORprime rate of 2.49%3.50% plus a margin of 1.75% for LIBOR2.00% on the alternate base rate borrowings and the prime rateweighted average LIBOR of 5.50%0.50% plus a margin of 0.75% on alternate base rate3.00% for the LIBOR borrowings. AtOn March 31, 2019,2022, the interest rate in effect on letters of credit was 1.75%3.00%. Commitment fees are charged at a rate ranging from 0.375% to 0.50%

The ABL Facility contains various affirmative and negative covenants, including financial reporting requirements and limitations on any unused capacity.

On July 5, 2018, we amended the Credit Agreement. In the amendment, the lenders consented to, subject to the consummationindebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of the Retail Propane disposition, release NGL Propane, LLC and its wholly-owned subsidiaries from its guarantyassets, distributions and other obligations underrestricted payments, investments (including acquisitions) and transactions with affiliates. The ABL Facility contains, as the loan documents, among other things. In return,only financial covenant, a fixed charge coverage ratio financial covenant that is tested based on the Partnership agreed to use the net proceeds from the Retail Propane disposition to pay down existing indebtedness no later than five business days after the consummation of the Retail Propane disposition.

On February 6, 2019, we amended the Credit Agreement, to, among other things, reset the basketfinancial statements for the repurchase of common units with a limit of $150 million in aggregatemost recently ended fiscal quarter upon the occurrence and during the remaining termcontinuation of the Credit Agreement, not to exceed $50 million per fiscal quarter, so long as, both immediately before and after giving pro forma effect to the repurchases, the Partnership’s Leverage Ratioa Cash Dominion Event (as defined in the Credit Agreement) is less than 3.25x and Revolving Availability (also as defined inABL Facility). At March 31, 2022, no Cash Dominion Event had occurred.

On April 13, 2022, we amended the Credit Agreement) is greater thanABL Facility to increase the commitments to $600.0 million under the accordion feature within the ABL Facility. As part of the amendment, we agreed to reduce the commitments back to $500.0 million on or equal to $200 million.before March 31, 2023. In addition, the amendment decreasessub-limit for letters of credit was increased to $250.0 million and the Maximum Total Leverage Indebtedness Ratio beginning September 30, 2019LIBOR benchmark was replaced with a further decrease beginning March 31, 2020 (as presented inan adjusted forward-looking term rate based on the table below), and amendssecured overnight financing rate (“SOFR”) as the defined term “Consolidated EBITDA” to exclude the “Gavilon Energy EPA Settlement” (as defined in the Credit Agreement) solely for the two quarters ending December 31, 2018 and March 31, 2019.interest rate benchmark.

The following table summarizes the debt covenant levels specified in the Credit Agreement as of March 31, 2019 (as modified on February 6, 2019):
    Senior Secured Interest Total Leverage
Period Beginning Leverage Ratio (1) Leverage Ratio (1) Coverage Ratio (2) Indebtedness Ratio (1)
March 31, 2019 4.50
 3.25
 2.75
 6.50
September 30, 2019 4.50
 3.25
 2.75
 6.25
March 31, 2020 and thereafter 4.50
 3.25
 2.75
 6.00
(1)Represents the maximum ratio for the period presented.
(2)Represents the minimum ratio for the period presented.

At March 31, 2019, our leverage ratio was approximately 2.63 to 1, our senior secured leverage ratio was approximately 0.58 to 1, our interest coverage ratio was approximately 3.70 to 1 and our total leverage indebtedness ratio was approximately 4.48 to 1.

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

We2022, we were in compliance with the covenants under the Credit Agreement at March 31, 2019.ABL Facility.

Senior Secured Notes

On June 19, 2012, we entered into the Note Purchase Agreement (as amended, the “Senior Secured Notes Purchase Agreement”) whereby we issued $250.0 million of senior secured notes in a private placement (the “Senior Secured Notes”). The Senior Secured Notes paid interest at a fixed rate of 6.65% which was payable quarterly. The Senior Secured Notes were required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We had the option to prepay outstanding principal, although we would incur a prepayment penalty. On December 29, 2017, we repurchased all of the remaining outstanding Senior Secured Notes. See below for the details related to the repurchase.


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Repurchases

The following table summarizes repurchases of Senior Secured Notes for the period indicated:
  Year Ended March 31,
  2018
  (in thousands)
Senior Secured Notes  
Notes repurchased $230,500
Cash paid (excluding payments of accrued interest) $250,179
Loss on early extinguishment of debt (1) $(23,971)
(1)Loss on the early extinguishment of debt for the Senior Secured Notes during the year ended March 31, 2018 is inclusive of the write off of debt issuance costs of $4.3 million. The loss is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.

Prior to the December 29, 2017 repurchase of all the remaining outstanding Senior Secured Notes, we made a semi-annual principal installment payment of $19.5 million on December 19, 2017.

Senior Unsecured Notes

The senior unsecured notes include as defined below, the 2019 Notes, 2021 Notes, 2023 Notes, 2025 Notes and 2026 Notes (collectively, the “Senior Unsecured Notes”).

The Partnership and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes, and the obligations under the Senior Unsecured Notes are fully and unconditionally guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving CreditABL Facility. The indentures governing the Senior Unsecured Notes contain various customary covenants, including certain covenants that govern our ability to (i) pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt, (ii) incur or guarantee additional indebtedness or issue preferred units, (iii) create or incur certain liens, (iv) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us, (v) consolidate, merge or transfer all or substantially all of our assets, and (vi) engage in transactions with affiliates.
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Our obligations under the Senior Unsecured Notes may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

Issuances

On July 9, 2014,October 24, 2016, we issued $400.0$700.0 million of 5.125% Senior Unsecured Notes Due 2019 (the “2019 Notes”).7.5% 2023 Notes. Interest is payable on January 15May 1 and July 15November 1 of each year. The 20192023 Notes were redeemedmature on November 1, 2023.

On February 22, 2017, we issued $500.0 million of 6.125% 2025 Notes. Interest is payable on March 15, 2019. See further discussion below.1 and September 1 of each year. The 2025 Notes mature on March 1, 2025.

On October 16, 2013,April 9, 2019, we issued $450.0 million of 6.875% Senior Unsecured7.5% 2026 Notes Due 2021 (the “2021 Notes”).in a private placement. Interest is payable on April 15 and October 15 of each year. The 2021 Notes were redeemed on October 16, 2018. See further discussion below.

On October 24, 2016, we issued $700.0 million of 7.50% Senior Unsecured Notes Due 2023 (the “2023 Notes”). Interest is payable on May 1 and November 1 of each year. The registration of the 2023 Notes became effective on July 11, 2017. The 2023 Notes mature on November 1, 2023.

On February 22, 2017, we issued $500.0 million of 6.125% Senior Unsecured Notes Due 2025 (the “2025 Notes”). Interest is payable on March 1 and September 1 of each year. The registration of the 2025 Notes became effective on July 11, 2017. The 2025 Notes mature on March 1, 2025.

On April 9, 2019, we issued $450.0 million of 7.50% Senior Unsecured Notes Due 2026 (the “2026 Notes”) in a private placement. The 2026 Notes bear interest, which is payable on April 15 and October 15 of each year, beginning on

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


October 15, 2019. We received net proceeds of $441.8 million, after the initial purchasers’ discount of $6.8 million and offering costs of $1.5 million. The 2026 Notes mature on April 15, 2026.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2026 Notes, and the obligations under the 2026 Notes are fully and unconditionally guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2026 Notes contains various customary covenants, including, (i) pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt, (ii) incur or guarantee additional indebtedness or issue preferred units, (iii) create or incur certain liens, (iv) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us, (v) consolidate, merge or transfer all or substantially all of our assets, and (vi) engage in transactions with affiliates.

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

We have the option to redeem all or a portion of the 2026 Notes at any time on or after April 15, 2022 at fixed redemption prices beginning at 103.750% on such date and declining annually and ratably to par for redemptions occurring on or after April 15, 2024 plus accrued and unpaid interest. At any time prior to April 15, 2022, we may redeem all or a portion of the 2026 Notes, at a redemption price equal to the “make whole price” specified in the indenture, plus accrued and unpaid interest.

In connection with the closing of the offering of the 2026 Notes, the Partnership entered into a registration rights agreement (the “Registration Rights Agreement”). Under the Registration Rights Agreement, the Partnership agreed to file a registration statement with the Securities and Exchange Commission (“SEC”) so that holders can exchange the 2026 Notes for registered notes that have substantially identical terms as the 2026 Notes and evidence the same indebtedness as the 2026 Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the 2026 Notes for a registered guarantee having substantially the same terms as the original guarantees. The Partnership is obligated to use commercially reasonable efforts to file an exchange offer registration statement with respect to the exchange notes and exchange guarantees and cause such exchange offer registration statement to become effective on or prior to 365 days after the closing of this offering. If the Partnership fails to satisfy this obligation, it will be required to pay to the holders of the 2026 Notes liquidated damages in an amount equal 0.25% per annum on the principal amount of the 2026 Notes held by such holder during the 90-day period immediately following the occurrence of such registration default, and such amount shall increase by 0.25% per annum at the end of such 90-day period.

Redemptions

The following table summarizes redemptions of Senior Unsecured Notes for the period indicated:
  Year Ended March 31,
  2019
  (in thousands)
2019 Notes (1)  
Notes redeemed $328,005
Cash paid (excluding payments of accrued interest) $329,719
Loss on early extinguishment of debt $(2,113)
   
2021 Notes (2)  
Notes redeemed $367,048
Cash paid (excluding payments of accrued interest) $373,358
Loss on early extinguishment of debt $(10,130)
(1)On March 15, 2019, we redeemed all of the remaining outstanding 2019 Notes. Loss on the early extinguishment of debt for the 2019 Notes during the year ended March 31, 2019 is inclusive of the write off of debt issuance costs of $0.4 million. The loss is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.
(2)On October 16, 2018, we redeemed all of the remaining outstanding 2021 Notes. Loss on the early extinguishment of debt for the 2021 Notes during the year ended March 31, 2019 is inclusive of the write off of debt issuance costs of $3.8 million. The loss is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Repurchases

The following table summarizes repurchases of Senior Unsecured Notes for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
2023 Notes
Notes repurchased$79,549 $52,072 $— 
Cash paid (excluding payments of accrued interest)$77,847 $33,566 $— 
Gain on early extinguishment of debt (1)$1,318 $18,096 $— 
2025 Notes
Notes repurchased$— $7,300 $1,815 
Cash paid (excluding payments of accrued interest)$— $3,647 $454 
Gain on early extinguishment of debt (2)$— $3,575 $1,341 
2026 Notes
Notes repurchased$6,000 $111,598 $— 
Cash paid (excluding payments of accrued interest)$5,320 $78,583 $— 
Gain on early extinguishment of debt (3)$610 $31,463 $— 
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
2019 Notes      
Notes repurchased $25,419
 $26,034
 $9,009
Cash paid (excluding payments of accrued interest) $25,406
 $26,002
 $7,099
(Loss) gain on early extinguishment of debt (1) $(34) $(140) $1,759
       
2021 Notes      
Notes repurchased $
 $
 $21,241
Cash paid (excluding payments of accrued interest) $
 $
 $14,094
Gain on early extinguishment of debt (2) $
 $
 $6,748
       
2023 Notes      
Notes repurchased $8,624
 $84,053
 $
Cash paid (excluding payments of accrued interest) $8,575
 $83,967
 $
Loss on early extinguishment of debt (3) $(63) $(1,136) $
       
2025 Notes      
Notes repurchased $
 $110,865
 $
Cash paid (excluding payments of accrued interest) $
 $107,050
 $
Gain on early extinguishment of debt (4) $
 $2,046
 $
(1)    Gain on early extinguishment of debt for the 2023 Notes during the years ended March 31, 2022 and 2021 is inclusive of the write off of debt issuance costs of $0.4 million and $0.4 million, respectively. The gain is reported within gain (loss) on early extinguishment of liabilities, net within our consolidated statements of operations.
(2)    Gain on early extinguishment of debt for the 2025 Notes during the years ended March 31, 2021 and 2020 is inclusive of the write off of debt issuance costs of $0.1 million and less than $0.1 million, respectively. The gain is reported within gain (loss) on early extinguishment of liabilities, net within our consolidated statements of operations.
(3)    Gain on early extinguishment of debt for the 2026 Notes during the years ended March 31, 2022 and 2021 is inclusive of the write off of debt issuance costs of $0.1 million and $1.6 million, respectively. The gain is reported within gain (loss) on early extinguishment of liabilities, net within our consolidated statement of operations.

(1)(Loss) gain on early extinguishment of debt for the 2019 Notes during the years ended March 31, 2019, 2018 and 2017 is inclusive of the write off of debt issuance costs of less than $0.1 million $0.2 million and $0.2 million, respectively. The (loss) gain is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.
(2)Gain on early extinguishment of debt for the 2021 Notes during the year ended March 31, 2017 is inclusive of the write off of debt issuance costs of $0.4 million. The gain is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.
(3)Loss on early extinguishment of debt for the 2023 Notes during the years ended March 31, 2019 and 2018 is inclusive of the write off of debt issuance costs of $0.1 million and $1.2 million, respectively. The loss is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.
(4)Gain on early extinguishment of debt for the 2025 Notes during the year ended March 31, 2018 is inclusive of the write off of debt issuance costs of $1.8 million. The gain is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.

Compliance

At March 31, 2019,2022, we were in compliance with the covenants under all of the Senior Unsecured Notes indentures.


Other Long-Term Debt

We have other notes payable related to equipment financing. The interest rates on these instruments range from 4.13% to 7.10% per year and have an aggregate principal balance of $5.3 million at March 31, 2019. Equipment loans totaling $41.7 million wereSawtooth credit agreement was paid off and terminated prior to us selling our ownership interest in Sawtooth on March 30, 2017, resulting in a loss on the early extinguishment of debt of $1.6 million, which was net of $0.1 million of debt issuance costs and $1.5 million of prepayment penalties. The loss is reported within (loss) gain on early extinguishment of liabilities, net within our consolidated statement of operations.June 18, 2021 (see Note 17).


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to 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 $41.7 million at March 31, 2022. The loan matures on November 1, 2027.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at March 31, 2019:2022:
Year Ending March 31,2026 Senior Secured NotesABL FacilitySenior Unsecured NotesOther
Long-Term
Debt
Total
(in thousands)
2023$— $— $— $2,378 $2,378 
2024— — 475,702 2,816 478,518 
2025— — 380,020 3,068 383,088 
20262,050,000 116,000 — 3,343 2,169,343 
2027— — 332,402 3,642 336,044 
Thereafter— — — 26,458 26,458 
Total$2,050,000 $116,000 $1,188,124 $41,705 $3,395,829 
Year Ending March 31, Revolving
Credit Facility
 Senior Unsecured Notes 
Other
Long-Term
Debt
 Total
  (in thousands)
2020 $
 $
 $648
 $648
2021 
 
 4,683
 4,683
2022 1,171,000
 
 
 1,171,000
2023 
 
 
 
2024 
 607,323
 
 607,323
Thereafter 
 389,135
 
 389,135
Total $1,171,000
 $996,458
 $5,331
 $2,172,789


Amortization of Debt Issuance Costs

Amortization expense for debt issuance costs related to long-term debt was $12.2 million, $7.8 million and $5.4 million during the years ended March 31, 2022, 2021 and 2020, respectively.

The following table summarizes expected amortization of debt issuance costs at March 31, 2022 (in thousands):

Year Ending March 31,
2023$12,049 
202411,560 
202510,801 
20268,526 
202746 
Thereafter
Total$42,988 

Note 98—Commitments and Contingencies


Legal 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. The GPOn 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 Partnership contend thatthe jury verdict, at least in respect of fraudulent misrepresentation,is not supportable by eithercontrolling law orthe evidentiary record.case to be set for a damages-only trial (the “December 5th Order”). Both defendants have a pending motion for judgment as a matter of law on the fraudulent misrepresentation claim and plan to file post-verdict motions as appropriatebeforeparties 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 quantummeruitand if needfraudulent 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 claim of quantum meruit damages. The date for the new trial, to be will file an appeallimited to the Delaware Supreme Court. It is our position thatquantum meruit claim, has been set by the awards, even if they each stand, are not cumulative.trial court for November 7, 2022. Any allocation of the ultimate verdict award, if any, between the GP and the Partnership will be
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

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 andand/or anyappellate process has run its courseconcluded and the verdict is final as a matter of law. Because the Partnership is a named defendant in the lawsuit, and any judgment ultimately awarded would be joint and several with the GP, we have determined that it is probable that the Partnership could be liable for a portion of this judgment. At this time, we believe the amount that could be allocated to the Partnership would not be material as it is estimated to be less than $4.0 million. As of March 31, 2019,2022, 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 March 31, 2019,2022, we have an environmental liability, measured on an undiscounted basis, of $2.5$1.8 million, which is recorded within accrued expenses and other payables in our 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.

In 2015, as previously disclosed, the U.S. Environmental Protection Agency (“EPA”) informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (“Gavilon Energy”), of alleged violations that occurred in 2011 by Gavilon Energy of

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by us in December 2013). On October 4, 2016, the U.S. Department of Justice, acting at the request of the EPA, filed a civil complaint in the Northern District of Iowa against Gavilon Energy and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint related to transactions between Gavilon Energy and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon Energy in 2011. On December 19, 2016, we filed a motion to dismiss the complaint. On January 9, 2017, the EPA filed an amended complaint. The amended complaint seeks an order declaring Western Dubuque’s RINs invalid and requiring the defendants to retire an equivalent number of valid RINs and that the defendants pay statutory civil penalties. On January 23, 2017, we filed a motion to dismiss the amended complaint. On May 24, 2017, the court denied our motion to dismiss. Subsequently, the EPA filed a second amended complaint seeking an order declaring Western Dubuque’s RINs invalid, an order requiring us to retire an equivalent number of valid RINs and an award against us of statutory civil penalties. In May 2018, the parties completed briefing on cross-motions for summary judgment concerning liability issues in the case. On July 3, 2018, the Court denied our summary judgment motion and largely granted the plaintiff’s two summary judgment motions on liability. On July 19, 2018, Gavilon Energy reached an agreement in principle with the EPA regarding the terms of a settlement of the case, which was memorialized in a consent decree lodged to the Court on September 27, 2018. Such terms will result in Gavilon Energy paying cash of $25.0 million and retiring 36 million RINs, over a twelve-month period. The consent decree was approved by the Court on November 8, 2018. The consent decree resolves all matters between Gavilon Energy and the EPA in connection with the above-described complaint. During the year ended March 31, 2019, we paid the EPA $12.5 million and retired all 36 million RINs. As of March 31, 2019, we have an accrual, which is included within accrued expenses and other payables in our consolidated balance sheet, of $12.5 million.

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 consolidated balance sheets (in thousands):
Balance at March 31, 2017 $8,181
Liabilities incurred 592
Liabilities assumed in acquisitions 21
Liabilities settled (549)
Accretion expense 888
Balance at March 31, 2018 9,133
Liabilities incurred 586
Liabilities assumed in acquisitions 438
Liabilities associated with disposed assets (1) (585)
Liabilities settled (546)
Accretion expense 697
Balance at March 31, 2019 $9,723

Balance at March 31, 2020$18,416 
Liabilities incurred7,952 
Liabilities associated with disposed assets (1)(22)
Accretion expense1,733 
Balance at March 31, 202128,079 
Liabilities incurred1,865 
Liabilities associated with disposed assets (2)(1,716)
Accretion expense1,713 
Balance at March 31, 2022$29,941 
(1)
This amount primarily relates to the sales of our Bakken and South Pecos water disposal businesses
(1)    Relates to the sale of certain permits, land and saltwater disposal facility (see Note 17).
(2)    Relates primarily to the disposition of Sawtooth (see Note 17) as well as the sale of certain water disposal wells.

(see Note 16).

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.


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at March 31, 2019 (in thousands):
Year Ending March 31, 
2020$127,718
2021105,697
202283,595
202354,599
202418,841
Thereafter41,845
Total$432,295


Amounts in the table above do not include operating leases related to our former Retail Propane segment (see Note 17).

Rental expense relating to operating leases was $150.7 million, $122.4 million, and $122.0 million during the years ended March 31, 2019, 2018 and 2017, respectively. Amounts do not include rental expense related to our former Retail Propane segment, as these amounts have been classified within discontinued operations within our consolidated statements of operations (see Note 17).

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on thetheir 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
F-26

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

expenses and other current assets and in other noncurrent assets in our 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 22).
).

The following table summarizes future minimum throughput payments under these agreements at March 31, 2019 are $43.2 million. The payments for these agreements will be completed at the end of fiscal year 2020. Of the total future minimum throughput payments, a third party has agreed to assume all rights and privileges and to be fully responsible for any minimum shipping fees due for actual shipments that are less than our allotted capacity related to $30.0 million of the fiscal year 2020 amount under a definitive agreement we signed during the three months ended June 30, 2018 (see Note 13).2022 (in thousands):

Construction Commitments

Year Ending March 31,
2023$35,314 
202435,410 
202530,897 
Total$101,621 
At March 31, 2019, we had construction commitments of $29.7 million
.

Sales and Purchase Contracts

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


At March 31, 2022, we had the following commodity purchase commitments:
Crude Oil (1)Natural Gas Liquids
ValueVolume
(in barrels)
ValueVolume
(in gallons)
(in thousands)
Fixed-Price Commodity Purchase Commitments:
2023$188,915 1,815 $15,619 14,280 
2024— — 4,588 6,048 
Total$188,915 1,815 $20,207 20,328 
Index-Price Commodity Purchase Commitments:
2023$3,875,415 42,808 $1,428,476 999,240 
20242,269,526 29,188 20,314 26,327 
20251,654,300 22,775 — — 
2026687,824 10,410 — — 
Total$8,487,065 105,181 $1,448,790 1,025,567 
(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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F-27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


At March 31, 2019, 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:        
2020 $60,227
 1,040
 $5,033
 7,545
2021 
 
 265
 378
Total $60,227
 1,040
 $5,298
 7,923
         
Index-Price Commodity Purchase Commitments:        
2020 $1,703,112
 30,363
 $564,013
 1,023,998
2021 526,420
 10,227
 1,199
 2,152
2022 411,071
 8,264
 
 
2023 269,990
 5,482
 
 
2024 200,022
 4,110
 
 
Total $3,110,615
 58,446
 $565,212
 1,026,150

(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.

At March 31, 2019,2022, we had the following commodity sale commitments (in thousands):
commitments:
  Crude Oil Natural Gas Liquids
  Value Volume
(in barrels)
 Value Volume
(in gallons)
Fixed-Price Commodity Sale Commitments:        
2020 $63,759
 1,090
 $45,626
 52,766
2021 
 
 1,395
 1,580
2022 
 
 86
 100
Total $63,759
 1,090
 $47,107
 54,446
         
Index-Price Commodity Sale Commitments:        
2020 $1,240,074
 20,500
 $594,877
 778,454
2021 
 
 1,634
 2,183
Total $1,240,074
 20,500
 $596,511
 780,637

Crude OilNatural Gas Liquids
ValueVolume
(in barrels)
ValueVolume
(in gallons)
(in thousands)
Fixed-Price Commodity Sale Commitments:
2023$187,058 1,839 $53,795 46,853 
2024— — 7,844 9,692 
2025— — 46 50 
Total$187,058 1,839 $61,685 56,595 
Index-Price Commodity Sale Commitments:
2023$3,093,185 32,502 $720,695 420,793 
2024837,815 10,248 1,074 842 
2025777,060 10,220 — — 
202628,698 390 — — 
Total$4,736,758 53,360 $721,769 421,635 

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 11)10) or inventory positions (described in Note 22).
).

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 consolidated balance sheet and are not included in the tables above. These contracts are included in the derivative disclosures in Note 11,10, and represent $86.5$52.0 million of our prepaid expenses and other current assets and $100.3$23.0 million of our accrued expenses and other payables at March 31, 2019.2022.



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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Other Commitments
Note 10—Equity
We have noncancelable agreements for product storage, railcar spurs and real estate. The following table summarizes future minimum payments under these agreements at March 31, 2022 (in thousands):
Year Ending March 31,
2023$12,092 
20248,204 
20253,257 
20261,195 
20271,182 
Thereafter5,502 
Total$31,432 

As part of the acquisition of HillstoneEnvironmental Partners, LLC (“Hillstone”), 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. During the years ended March 31, 2022, 2021 and 2020, we recorded $2.1 million, $2.6 million and $0.8 million, respectively, within operating expense in our consolidated statements of operations. At March 31, 2022, the range of potential payments we could be obligated to make pursuant to the subsidy agreement could be from $0.0 million to $2.4 million.

Note 9—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
F-28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

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 or obligations. As of March 31, 2022, 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 and warrants that were exercised for common units during the yearyears ended March 31, 2019,2022, 2021 and 2020, we issued 3,0391,103, 823 and 4,268, respectively, notional units to our general partner forwhich represented less than $0.1 million in each of the years, in order to maintain its 0.1% interest in us.

In connection with the issuance of common units for the vesting of restricted units and warrants that were exercised for common units during the year ended March 31, 2018, we issued 1,294 notional units to our general partner for less than $0.1 million in order to maintain its 0.1% interest in us.

In connection with the issuance of common units for the vesting of restricted units, ATM Program (as defined
herein) and the equity issuance in February 2017, as discussed within this note, as well as common units issued for a retail propane acquisition during the year ended March 31, 2017, we issued 16,026 notional units to our general partner for $0.3 million in order to maintain its 0.1% interest in us.

Equity Issuances

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. This ATM Program is registered with the SEC on an effective registration statement on Form S-3. During the year ended March 31, 2017, we sold 3,321,135 common units for net proceeds of $64.4 million (net of offering costs of $0.9 million). We did not sell any common units under the ATM Program during the years ended March 31, 2019 and 2018. As of March 31, 2019, approximately $134.7 million remained available for sale under the ATM Program.

On February 22, 2017, we completed a public offering of 10,120,000 common units. We received net proceeds of $222.5 million (net of offering costs of $11.8 million).

Common Unit Repurchase Program

On August 29, 2017,30, 2019, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0$150.0 million of our outstanding common units through December 31, 2017September 30, 2021 from time to time in the open market or in other privately negotiated transactions. Undertransactions. We did not repurchase any units under this program,plan and this plan has expired.

we repurchased 1,516,848common units for an aggregate price
Suspension of $15.0 million, including commissions. This programCommon Unit and Preferred Unit Distributions

The board of directors of our general partner temporarily suspended all distributions (common unit distributions which began with the quarter ended on December 31, 2017.2020 and preferred unit distributions which began 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 7.


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Our Distributions

The following table summarizes distributions declared on our common units during the last three fiscal years:years ended March 31, 2021 and 2020:
Date DeclaredRecord DatePayment DateAmount
Per Unit
Amount Paid to
Limited Partners
Amount Paid to
General Partner
(in thousands)(in thousands)
April 24, 2019May 7, 2019May 15, 2019$0.3900 $49,127 $85 
July 23, 2019August 7, 2019August 14, 2019$0.3900 $49,217 $85 
October 23, 2019November 7, 2019November 14, 2019$0.3900 $49,936 $86 
January 23, 2020February 7, 2020February 14, 2020$0.3900 $50,056 $86 
April 27, 2020May 7, 2020May 15, 2020$0.2000 $25,754 $26 
July 23, 2020August 6, 2020August 14, 2020$0.2000 $25,754 $26 
October 27, 2020November 6, 2020November 13, 2020$0.1000 $12,877 $13 
Date Declared Record Date Payment Date 
Amount
Per Unit
 
Amount Paid to
Limited Partners
 
Amount Paid to
General Partner
        (in thousands) (in thousands)
April 21, 2016 May 3, 2016 May 13, 2016 $0.3900
 $40,626
 $70
July 21, 2016 August 4, 2016 August 12, 2016 $0.3900
 $41,146
 $71
October 20, 2016 November 4, 2016 November 14, 2016 $0.3900
 $41,907
 $72
January 19, 2017 February 3, 2017 February 14, 2017 $0.3900
 $42,923
 $74
April 24, 2017 May 8, 2017 May 15, 2017 $0.3900
 $46,870
 $80
July 20, 2017 August 4, 2017 August 14, 2017 $0.3900
 $47,460
 $81
October 19, 2017 November 6, 2017 November 14, 2017 $0.3900
 $47,000
 $81
January 23, 2018 February 6, 2018 February 14, 2018 $0.3900
 $47,223
 $81
April 24, 2018 May 7, 2018 May 15, 2018 $0.3900
 $47,374
 $82
July 24, 2018 August 8, 2018 August 14, 2018 $0.3900
 $47,600
 $82
October 23, 2018 November 8, 2018 November 14, 2018 $0.3900
 $48,260
 $83
January 22, 2019 February 6, 2019 February 14, 2019 $0.3900
 $48,373
 $83
April 24, 2019 May 7, 2019 May 15, 2019 $0.3900
 $49,127
 $85


Class A Convertible Preferred Units

On April 21, 2016, we entered into a private placement agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Class A Preferred Units”) to Oaktree Capital Management L.P. and its co-investors (“Oaktree”). On June 23, 2016, the private placement agreement was amended to increase the aggregate principal amount from $200 million to $240 million. We received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of 19,942,169 Class A Preferred Units and 4,375,112 warrants.warrants, which have an exercise price of $0.01. As noted below, the remaining Class A Preferred Units were redeemed and all remaining warrants were exercised during the year ended March 31, 2020.

We paypaid a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Class A Preferred Units to the extent declared by the board of directors of our general partner. To the extent declared, such distributions will bewere paid for each such quarter within 45 days after each quarter end.

The following table summarizes distributions declared on our Class A Preferred Units during the last three fiscal years:
Date Declared Payment Date Amount Paid to Class A
Preferred Unitholders
    (in thousands)
July 21, 2016 August 12, 2016 $1,795
October 20, 2016 November 14, 2016 $6,449
January 19, 2017 February 14, 2017 $6,449
April 24, 2017 May 15, 2017 $6,449
July 20, 2017 August 14, 2017 $6,449
October 19, 2017 November 14, 2017 $6,449
January 23, 2018 February 14, 2018 $6,449
April 24, 2018 May 15, 2018 $6,449
July 24, 2018 August 14, 2018 $6,449
October 23, 2018 November 14, 2018 $6,449
January 22, 2019 February 14, 2019 $6,449
April 24, 2019 May 10, 2019 $4,034


If the Class A Preferred Unit quarterly distribution is not made in full in cash for any quarter, the Class A Preferred Unit distribution rate will increase by one quarter of a percentage point (0.25%) per year beginning with distributions for the first six-month period that a payment default is in effect, and will further increase by an additional one quarter of a percentage point (0.25%) beginning with distributions for the next six-month period during which a payment default remains in effect. The

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


deficiency rate shall not exceed 11.25% per year; as long as the default is occurring, the amount of accrued but unpaid Class A Preferred Unit quarterly distributions shall increase at an annual rate of 10.75%, compounded quarterly, until paid in full.

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

At any time after the third anniversary of the initial closing date, the Class A preferred unitholders shall have the right to convert all of the outstanding Class A Preferred Units at a price per Class A Preferred Unit equal to the purchase price multiplied by the conversion multiple then in effect, which may be settled in common units, cash or a combination, at our discretion. The conversion multiple means if our common units are trading at or above $12.035 (“the initial conversion price”), the conversion price is not adjusted. However, if the conversion price is less than the initial conversion price, the conversion price will be reset to the greater of (i) the adjusted volume weighted average price of our common units for the 15 trading days immediately preceding the third anniversary of the closing date or (ii) $5.00.

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

Under the private placement agreement, we are required to file within 180 days of the initial closing date a registration statement registering the resales of common units issued or to be issued upon conversion of the Class A Preferred Units or exercise of the warrants and have the registration statement declared effective within 360 days after the closing date. We are required to continue to maintain the effectiveness of the registration statement until all securities have been sold. The Partnership’s registration statement was declared effective by the SEC on November 23, 2016.

The warrants have an eight year term, after which unexercised warrants will expire. The holders of the warrants may exercise one-third of the warrants from and after the first anniversary of the original issue date, another one-third of the warrants from and after the second anniversary and the final one-third of the warrants from and after the third anniversary. Upon a change of control or in the event we exercise our redemption right with respect to the Class A Preferred Units, all unvested warrants shall immediately vest and be exercisable in full. The warrants have an exercise price of $0.01. During the year ended March 31, 2019, 228,797 warrants were exercised for common units and we received proceeds of less than $0.1 million, and we repurchased 1,229,575 unvested warrants for a total purchase price of $15.0 million on April 26, 2018. During the year ended March 31, 2018, 607,653 warrants were exercised for common units and we received proceeds of less than $0.1 million, and we repurchased 850,716 unvested warrants for a total purchase price of $10.5 million on June 23, 2017. As of March 31, 2019, we had 1,458,371 warrants that remain outstanding, which were all exercised for common units on April 5, 2019 (see below for a further discussion).

We allocated the net proceeds on a relative fair value basis to the Class A Preferred Units, ($186.4 million), which includes the value of a beneficial conversion feature, and warrants ($48.6 million). As discussed below, $131.5 million of the amount allocated to the Class A Preferred Units was allocated to the intrinsic value of the beneficial conversion feature. A beneficial conversion feature is defined as a nondetachable conversion feature that is in the money at the commitment date. Per the applicable accounting guidance, we are required to allocate a portion of the proceeds allocated to the Class A Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per unit value of our common units at the issuance date) and the proceeds attributed to the Class A Preferred Units.warrants. We recordrecorded the accretion attributable to the beneficial conversion feature as a deemed distribution using the effective interest method over the three year period prior to the effective dates of the holders’ conversion right.distribution. Accretion for the beneficial conversion feature was $67.2 million, $18.8 million and $9.0$36.5 million for the yearsyear ended March 31, 2019, 2018 and 2017, respectively.2020.


F-41
F-29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


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

On April 5, 2019, we made a partial redemption ofredeemed 7,468,978 of the Class A Preferred Units. The applicable Class A redemption premium on the date of redemptionprice was $13.389 per Class A Preferred Unit, calculated at 111.25% of $12.035 (the Class A Preferred Unit price), and theplus accrued but unpaid and accumulated distributions of $0.338. The amount per Class A Preferred Unit paid to each Class A preferred unitholder was $13.727, for a total payment of $102.5 million. On April 5, 2019, Oaktree also exercised all of its 1,458,371 outstanding warrants to purchase common units were exercised for proceeds of less than $0.1 million.

On May 11, 2019, we redeemed the remaining 12,473,191 outstanding Class A Preferred Units. The applicable Class A redemption premium on the date of redemptionprice was $13.2385 per Class A Preferred Unit, calculated at 110% of $12.035 (the Class A Preferred Unit price), and theplus accrued but unpaid and accumulated distributions of $0.1437. The amount per Class A Preferred Unit paid to each Class A preferred unitholder was $13.3822, for a total payment of $166.9 million. In addition, we paid the Class A preferred unitholders the distribution declared on April 24, 2019 for the quarter ended March 31, 2019 as noted above.of $4.0 million, or $0.3234 per unit, which was paid to the holders of the Class A Preferred Units on May 10, 2019.

Class B Preferred Units

On June 13, 2017, we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $202.7 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.7 million).

On July 2, 2019, we issued 4,185,642 Class B Preferred Units to fund a portion of the purchase price for the Mesquite acquisition.

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

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

The following table summarizes distributions declared on our Class B Preferred Units duringfor the last two fiscal years:years ended March 31, 2021 and 2020:
Date Declared Record Date Payment Date Amount Paid to Class B
Preferred Unitholders
      (in thousands)
September 18, 2017 September 29, 2017 October 16, 2017 $5,670
December 19, 2017 December 29, 2017 January 15, 2018 $4,725
March 19, 2018 April 2, 2018 April 16, 2018 $4,725
June 19, 2018 July 2, 2018 July 16, 2018 $4,725
September 12, 2018 October 1, 2018 October 15, 2018 $4,725
December 17, 2018 December 31, 2018 January 15, 2019 $4,725
March 15, 2019 April 1, 2019 April 15, 2019 $4,725
Date DeclaredRecord DatePayment DateAmount Per UnitAmount Paid to Class B
Preferred Unitholders
(in thousands)
March 15, 2019April 1, 2019April 15, 2019$0.5625 $4,725 
June 14, 2019July 1, 2019July 15, 2019$0.5625 $4,725 
September 16, 2019October 1, 2019October 15, 2019$0.5625 $7,079 
December 16, 2019December 31, 2019January 15, 2020$0.5625 $7,079 
March 16, 2020March 31, 2020April 15, 2020$0.5625 $7,079 
June 15, 2020June 30, 2020July 15, 2020$0.5625 $7,079 
September 15, 2020September 30, 2020October 15, 2020$0.5625 $7,079 
December 17, 2020January 1, 2021January 15, 2021$0.5625 $7,079 


The current distribution amount paid on April 15, 2019rate for the Class B Preferred Units is included in accrued expenses and other payables in our consolidated balance sheet at9.00% per year of the $25.00 liquidation preference per unit (equal to $2.25 per unit per year). For the quarter ended March 31, 2019.2022, we did not declare or pay distributions to the holders of the Class B Preferred Units, thus the quarterly distribution for March 31, 2022 is $0.5625 and the cumulative distributions since suspension for each Class B Preferred unit is $2.8125. In addition, the amount of cumulative but unpaid distribution shall continue to accumulate at the then applicable rate until all unpaid distributions have been paid in full. The total amount due as of March 31, 2022 is $36.9 million.

F-42
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Class C Preferred Units

On April 2, 2019, we issued 1,800,000 of our 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $43.1$42.9 million (net of the underwriters’ discount of $1.4 million and estimated offering costs of $0.5$0.7 million).

At any time on or after April 15, 2024, we may redeem our Class C Preferred Units, in whole or in part, at a redemption price of $25.00 per Class C Preferred Unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Class C Preferred Units upon a change of control as defined in our partnership agreement. If we choose not to redeem the Class C Preferred Units, the Class C preferred unitholders may have the ability to convert the Class C Preferred Units to common units at the then applicable conversion rate. Class C preferred unitholders have no voting rights except with respect to certain matters set forth in our partnership agreement.

Distributions on the Class C Preferred Units are payable on the 15th day of each January, April, July and October of each year to holders of record on the first day of each payment month. The initial distribution rate for the Class C Preferred Units from and including the date of original issue to, but not including, April 15, 2024, is 9.625% per year of the $25.00 liquidation preference per unit (equal to $2.41 per unit per year). On and after April 15, 2024, distributions on the Class C Preferred Units will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in accordance with the partnership agreement) plus a spread of 7.384%.

The following table summarizes distributions declared on our Class C Preferred Units for the years ended March 31, 2021 and 2020:
Amount Paid to Class C
Date DeclaredRecord DatePayment DateAmount Per UnitPreferred Unitholders
(in thousands)
June 14, 2019July 1, 2019July 15, 2019$0.5949 $1,071 
September 16, 2019October 1, 2019October 15, 2019$0.6016 $1,083 
December 16, 2019December 31, 2019January 15, 2020$0.6016 $1,083 
March 16, 2020March 31, 2020April 15, 2020$0.6016 $1,083 
June 15, 2020June 30, 2020July 15, 2020$0.6016 $1,083 
September 15, 2020September 30, 2020October 15, 2020$0.6016 $1,083 
December 17, 2020January 1, 2021January 15, 2021$0.6016 $1,083 

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 March 31, 2022, we did not declare or pay distributions to the holders of the Class C Preferred Units, thus the quarterly distribution for each Class C Preferred Unit is $0.6016 and the cumulative distribution since suspension for each Class C Preferred Unit is $3.0078. 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 March 31, 2022 is $5.7 million.

Class D Preferred Units

On July 2, 2019, we completed a private placement of an aggregate of 400,000 preferred units (“Class D Preferred Units”) and warrants exercisable to purchase an aggregate of 17,000,000 common units for an aggregate purchase price of $400.0 million. The private placement resulted in aggregate net proceeds to us of approximately $385.4 million (net of a closing fee of $14.6 million payable to affiliates of the purchasers and certain estimated expenses and expense reimbursements). We allocated the net proceeds, on a relative fair value basis, to the Class D Preferred Units ($343.7 million) and warrants ($41.7 million). Proceeds from this issuance of Class D Preferred Units were used to fund a portion of the purchase price for the Mesquite acquisition.

On October 31, 2019, we completed a private placement of an aggregate of 200,000 Class D Preferred Units and warrants exercisable to purchase an aggregate of 8,500,000 common units for an aggregate purchase price of $200.0 million. The private placement resulted in aggregate net proceeds to us of approximately $194.7 million (net of a closing fee of $5.3 million payable to affiliates of the purchasers and certain estimated expenses and expense reimbursements). We allocated the net proceeds, on a relative fair value basis, to the Class D Preferred Units ($183.6 million) and warrants ($11.1 million). Proceeds from this issuance of Class D Preferred Units were used to fund a portion of the purchase price for the Hillstone acquisition.

F-31

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

The holders of the Class D Preferred Units are entitled to receive a cumulative, quarterly distribution in arrears on each Class D Preferred Unit then held at an annual rate of (i) 9.00% per annum for all periods during which the Class D Preferred Units are outstanding beginning on July 2, 2019 (the “Closing Date”) and ending on the date and including the last day of the eleventh full quarter following Closing Date, (ii) 10.00% per annum for all periods during which the Class D Preferred Units are outstanding beginning on and including the first day of the twelfth full quarter following the Closing Date and ending on the last day of the nineteenth full quarter following the Closing Date, and (iii) thereafter, 10.00% per annum or, at the purchasers’ election from time to time, a floating rate equal to the applicable three-month LIBOR (or alternative rate as determined in accordance with the partnership agreement), plus 7.00% per annum.

The following table summarizes cash distributions declared on our Class D Preferred Units for the years ended March 31, 2021 and 2020:
Amount Paid to Class D
Date DeclaredRecord DatePayment DateAmount Per UnitPreferred Unitholders
(in thousands)
October 23, 2019November 7, 2019November 14, 2019$11.25 $4,450 
January 23, 2020February 7, 2020February 14, 2020$11.25 $6,075 
April 27, 2020May 7, 2020May 15, 2020$11.25 $6,868 
July 23, 2020August 6, 2020August 14, 2020$11.25 $6,946 
October 27, 2020November 6, 2020November 13, 2020$26.01 $15,608 
January 20, 2021February 5, 2021February 12, 2021$26.01 $15,608 

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 Partnership Agreement. For the quarter ended March 31, 2022, we did not declare or pay distributions to the holders of the Class D Preferred Units, thus the average quarterly distribution at March 31, 2022 is $27.32 and the average cumulative distribution since suspension for each Class D Preferred unit is $135.28. 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 March 31, 2022 is $85.4 million.

The distributions for the quarters ended September 30, 2020 and December 31, 2020 include a 1.0% rate increase due to us exceeding the adjusted total leverage ratio, as defined within the Amended and Restated Partnership Agreement. The distributions paid in cash for the three months ended June 30, 2020 of $6.9 million represented 50% of the Class D Preferred Units distributions amount, as represented in the table above. In accordance with the terms of our Amended and Restated Partnership Agreement, the value of each Class D Preferred Unit automatically increased by the non-cash accretion which was approximately $6.9 million in the aggregate with respect to the distribution for the three months ended June 30, 2020. The distributions paid in cash for the year ended March 31, 2020 of $17.4 million represented 50% of the Class D Preferred Units distribution amount. In accordance with the terms of our Amended and Restated Partnership Agreement, the value of each Class D Preferred Unit automatically increased by the non-cash accretion, which was approximately $17.4 million in the aggregate with respect to the distributions for the year ended March 31, 2020.

F-32

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

At any time after the Closing Date, the Partnership shall have the right to redeem all of the outstanding Class D Preferred Units at a price per Class D Preferred Unit equal to the sum of the then-unpaid accumulations with respect to such Class D Preferred Unit and the greater of either the applicable multiple on invested capital or the applicable redemption price based on an applicable internal rate of return, as more fully described in the Amended and Restated Partnership Agreement. At any time on or after the eighth anniversary of the Closing Date, each Class D Preferred Unitholder will have the right to require the Partnership to redeem on a date not prior to the 180th day after such anniversary all or a portion of the Class D Preferred Units then held by such preferred unitholder for the then-applicable redemption price, which may be paid in cash or, at the Partnership’s election, a combination of cash and a number of common units not to exceed one-half of the aggregate then-applicable redemption price, as more fully described in the Amended and Restated Partnership Agreement. Upon a Class D Change of Control (as defined in the Amended and Restated Partnership Agreement), each Class D Preferred Unitholder will have the right to require the Partnership to redeem the Class D Preferred Units then held by such Preferred Unitholder at a price per Class D Preferred Unit equal to the applicable redemption price. The Class D Preferred Units generally will not have any voting rights, except with respect to certain matters which require the vote of the Class D Preferred Units. The Class D Preferred Units generally do not have any voting rights, except that the Class D Preferred Units shall be entitled to vote as a separate class on any matter on which unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Class D Preferred Units in relation to other classes of Partnership Interests (as defined in the Amended and Restated Partnership Agreement) or as required by law. The consent of a majority of the then-outstanding Class D Preferred Units, with one vote per Class D Preferred Unit, shall be required to approve any matter for which the preferred unitholders are entitled to vote as a separate class or the consent of the representative of the Class D Preferred Unitholders, as applicable.

The warrants issued in the July 2, 2019 private placement are exercisable for, in the aggregate, 17,000,000 common units, of which 10,000,000 were issued with an exercise price of $17.45 per common unit (the “Premium Warrants”), and the remaining warrants to purchase 7,000,000 common units were issued with an exercise price of $14.54 per common unit (the “Par Warrants”). The warrants issued in the October 31, 2019 private placement are exercisable for, in the aggregate, 8,500,000 common units, of which, 5,000,000 (which are considered Premium Warrants) were issued with an exercise price of $16.28 per common unit, and the remaining warrants to purchase 3,500,000 (which are considered Par Warrants) common units were issued with an exercise price of $13.56 per common unit. The warrants may be exercised from and after the first anniversary of the date of issuance. Unexercised warrants will expire on the tenth anniversary of the date of issuance. The warrants will not participate in cash distributions.

Upon a change of control, all unvested warrants shall immediately vest and be exercisable in full. A change of control occurs when (a) the current general partner owners cease to own, directly or indirectly, at least 50% of the outstanding voting securities of the general partner, (b) the general partner withdraws or is removed by the limited partners, (c) the common units are no longer listed on a national exchange, or (d) the general partners and/or its affiliates become beneficial owner, directly or indirectly, of 80% or more of the outstanding common units or any transaction or event that occurs due to default on our credit agreement.

Board Rights Agreement

In connection with the issuance of the Class D Preferred Units, we entered into a board rights agreement pursuant to which affiliates of the purchasers of the Class D Preferred Units (“Purchasers”) will have the right to designate one director on the board of directors of our general partner, so long as the Purchasers and their respective affiliates, in the aggregate, own either at least (i) (A) 50% of the number of Class D Preferred Units issued on the Closing Date or (B) 50% of the aggregate liquidation preference of any class or series of Class D Parity Securities (as defined in the Amended and Restated Partnership Agreement), or (ii) warrants and/or common units that, in the aggregate, comprise 10% or more of the then-outstanding common units.

Amended and Restated Partnership Agreement

On February 4, 2021, NGL Energy Holdings LLC executed the First Amendment to the Seventh Amended and Restated Agreement of Limited Partnership for the purpose of amending certain consent rights in relation to the Class D Preferred Units.

On October 31, 2019, NGL Energy Holdings LLC executed the Seventh Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of Class D Preferred Units are defined in the Amended and Restated Partnership Agreement. The Class D Preferred Units rank senior to the common units with respect to payment of distributions and distribution of assets upon liquidation, dissolution and winding up, and are in parity with the Class B Preferred Units and Class C Preferred Units. The Class D Preferred Units have no stated maturity, but we may redeem the Class D Preferred Units at any time after the Closing Date or upon the occurrence of a change in control.
F-33

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


On April 2, 2019, NGL Energy Holdings LLC executed the Fifth Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Class C Preferred Units are defined in the amendedAmended and restated partnership agreement.Restated Partnership Agreement. The Class C Preferred Units rank senior to the common units, with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up, and are on parity with the Class A Preferred Units (see above discussion regarding the redemption of these units) and Class B Preferred Units. The Class C Preferred Units have no stated maturity but we may redeem the Class C Preferred Units at any time on or after April 15, 2024 or upon the occurrence of a change in control.

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

On June 24, 2016, NGL Energy Holdings LLC executed the Third Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Class A Preferred Units are defined in the amended and restated partnership agreement. The Class A Preferred Units rank senior to the common units, with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Class A Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless redeemed by the Partnership or converted into common units at the election of the Partnership or the Class A preferred unitholders or in connection with a change of control. See above for a discussion regarding the redemption of the Class A Preferred Units.

Equity-Based Incentive Compensation

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

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


F-43

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


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

The following table summarizes the Service Award activity during the year ended March 31, 2022:
Weighted-Average
Grant Date
Number ofFair Value
UnitsPer Unit
Unvested Service Award units at March 31, 2021446,975 $6.61
Units granted3,294,750 $2.15
Units vested and issued(1,146,800)$3.72
Units forfeited(406,125)$2.63
Unvested Service Award units at March 31, 20222,188,800 $2.15

The weighted-average grant prices for the years ended March 31, 2019, 20182022, 2021 and 2017:2020 were $2.15, $3.76 and $12.84, respectively.
Unvested Service Award units at March 31, 20162,297,132
Units granted3,124,600
Units vested and issued(2,350,082)
Units forfeited(363,150)
Unvested Service Award units at March 31, 20172,708,500
Units granted1,964,911
Units vested and issued(2,260,011)
Units forfeited(134,525)
Unvested Service Award units at March 31, 20182,278,875
Units granted3,141,993
Units vested and issued(2,833,968)
Units forfeited(278,500)
Unvested Service Award units at March 31, 20192,308,400


In connection with the vesting of certain restrictedService Award units during the year ended March 31, 2019,2022, we canceled 26,99344,769 of the newly-vested common units in satisfaction of $0.3$0.1 million of employee tax liability paid by us. Pursuant to the termsexpiration of the LTIP thesediscussed below, those canceled units are not available for future grants under the LTIP.grants.

The following table summarizes the scheduled vestingAs of ourMarch 31, 2022, there are 1,459,075 unvested Service Award units atwhich are expected to vest during the year ended March 31, 2019:2023 and 729,725 unvested Service Award units which are expected to vest during the year ended March 31, 2024.
Year Ending March 31, Number of Units
2020 1,005,725
2021 869,425
2022 433,250
Total 2,308,400


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. 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-dategrant date value of the award that is vested at that date.

During the years ended March 31, 2019, 20182022, 2021 and 2017,2020, we recorded compensation expense related to Service Award units of $12.0$3.3 million, $16.2$4.7 million and $56.2$8.5 million, respectively.

During the years ended March 31, 2022 and 2021, 0 Service Award units were granted as performance bonuses. Of the restrictedService Award units granted and vested during the year ended March 31, 2019, 1,745,8012020, 1,886,131 units were granted as a bonus for performance bonuses. The total amount of the bonus payment for the year ended March 31, 2020 was $24.5 million, of which we had accrued $8.7 million as of March 31, 2019.

As of March 31, 2022, we had estimated future expense of $3.1 million on unvested Service Award units which we expect to record during the year ended March 31, 2018. The total amount of these bonus payments was $20.42023 and $1.3 million of which we had accrued $6.3 million as of March 31, 2018. Also, 59,393 units were granted and vested as incentive compensation for the year ended March 31, 2018. The value of these awards was $0.7 million and was recorded within general and administrative expense in our consolidated statement of operations for the year ended March 31, 2018.

Of the restricted units granted and vestedexpect to record during the year ended March 31, 2019, 176,817 units were granted as a bonus for performance during the year ended March 31, 2019. The total amount of these bonus payments was $2.4 million.

Of the restricted units granted and vested during the year ended March 31, 2017, 1,008,091 units were granted as a bonus for performance during the year ended March 31, 2016. We accrued expense of $16.8 million during the year ended March 31, 2016 as an estimate of the value of such bonus units that would be granted. During the year ended March 31, 2017, we recorded an additional $2.2 million to true up the estimate to the $19.0 million of actual expense associated with these

2024.
F-44
F-34

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


bonuses. SinceAs the LTIP expired on May 10, 2021, we have no common units were not granted until August 2016, the full $19.0 million is reflected in the expense during the year ended March 31, 2017.

The following table summarizes the estimated future expense we expect to record on theavailable for grant and any current unvested Service Award units at March 31, 2019 (in thousands):Awards that are forfeited or canceled will not be available for future grants.
Year Ending March 31,  
2020 $8,168
2021 4,154
2022 1,350
Total $13,672


Beginning in April 2015, our general partner granted units that vest contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”). These Performance Award units were granted to certain employees. Performance was to be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. During the three months ended December 31, 2018, the compensation committee of the board of directors of our general partner terminated the Performance Award plan and all unvested outstanding Performance Awards units were canceled. Accordingly, as no replacement awards were granted, all previously unrecognized compensation cost was expensed as of the cancellation date. During the year ended March 31, 2019, we recorded compensation expense related to the cancellation of the Performance units of $3.1 million which was recorded within general and administrative expense in our consolidated statement of operations for the year ended March 31, 2019.

The following table summarizes the Performance Award activity during the years ended March 31, 2019, 2018 and 2017:
Unvested Performance Award units at March 31, 2016637,382
Units granted932,309
Units forfeited(380,691)
Unvested Performance Award units at March 31, 20171,189,000
Units granted224,000
Units forfeited(496,000)
Unvested Performance Award units at March 31, 2018917,000
Units forfeited(445,500)
Units canceled(471,500)
Unvested Performance Award units at March 31, 2019


During the July 1, 2015 through June 30, 2018 performance period, the return on our common units was below the return of the 50th percentile of our peer companies in the Index. As a result, no Performance Award units vested on July 1, 2018 and performance units with the July 1, 2018 vesting date are considered to be forfeited.

The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. The significant inputs used to calculate the fair value of these awards include (i) the price per our common units at the grant date and the beginning of the performance period, (ii) a compounded risk-free interest rate, (iii) our compounded dividend yield, (iv) our historical volatility, (v) the volatility and correlations of our peers and (vi) the remaining performance period. We recorded the expense on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. Any Performance Awards not earned at the end of the performance period will terminate, expire and otherwise be forfeited by the participants. During the years ended March 31, 2019, 2018 and 2017, we recorded compensation expense related to Performance Award units of $4.9 million (including amounts recorded related to the cancellation of the Performance Award plan (see above)), $5.3 million and $7.2 million, respectively.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding common units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. When an award is forfeited,

F-45

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. The LTIP provides that units allocated to satisfy tax withholding obligations are not deemed to reduce availability for awards under the LTIP. Following a review of the LTIP, the compensation committee of the board of directors of our general partner determined that units vested after July 1, 2016 were inadvertently counted as a reduction to the Partnership’s LTIP reserve. Accordingly, after making the adjustments as provided for in the LTIP, as of March 31, 2019, there are approximately 3.3 million units remaining available for issuance under the LTIP.

Note 1110—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 consolidated balance sheet at the dates indicated:
  March 31, 2019 March 31, 2018
  Derivative
Assets
 Derivative
Liabilities
 Derivative
Assets
 Derivative
Liabilities
  (in thousands)
Level 1 measurements $49,509
 $(7,273) $5,093
 $(20,186)
Level 2 measurements 86,785
 (100,564) 48,752
 (54,410)
  136,294
 (107,837) 53,845
 (74,596)
         
Netting of counterparty contracts (1) (7,501) 7,501
 (2,922) 2,922
Net cash collateral (held) provided (18,271) (208) (1,762) 17,263
Commodity derivatives $110,522
 $(100,544) $49,161
 $(54,411)
March 31, 2022March 31, 2021
Derivative
Assets
Derivative
Liabilities
Derivative
Assets
Derivative
Liabilities
(in thousands)
Level 1 measurements$73,353 $(47,585)$12,312 $(17,857)
Level 2 measurements51,968 (27,372)37,520 (24,474)
125,321 (74,957)49,832 (42,331)
Netting of counterparty contracts (1)(47,585)47,585 (12,648)12,648 
Net cash collateral provided839 — 2,660 5,543 
Commodity derivatives$78,575 $(27,372)$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.
(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 consolidated balance sheets at the dates indicated:
March 31,
20222021
(in thousands)
Prepaid expenses and other current assets$78,575 $39,844 
Accrued expenses and other payables(27,108)(21,562)
Other noncurrent liabilities(264)(2,578)
Net commodity derivative asset$51,203 $15,704 
  March 31,
  2019 2018
  (in thousands)
Prepaid expenses and other current assets $110,521
 $49,161
Other noncurrent assets 1
 
Accrued expenses and other payables (100,372) (51,039)
Other noncurrent liabilities (172) (3,372)
Net commodity derivative asset (liability) $9,978
 $(5,250)



F-46F-35

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to 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 March 31, 2019:      
Crude oil fixed-price (1) April 2019–December 2020 (1,961) 1,014
Propane fixed-price (1) April 2019–March 2020 198
 608
Refined products fixed-price (1) April 2019–January 2021 (2,296) 22,079
Other April 2019–March 2022   4,756
      28,457
Net cash collateral held     (18,479)
Net commodity derivative asset     $9,978
       
At March 31, 2018:      
Cross-commodity (2) April 2018–March 2019 155
 $(430)
Crude oil fixed-price (1) April 2018–December 2019 (1,376) $(8,960)
Crude oil index (1) April 2018–April 2018 (10) $(6)
Propane fixed-price (1) April 2018–February 2019 14
 1,849
Refined products fixed-price (1) April 2018–January 2020 (5,419) (17,081)
Refined products index (1) April 2018–April 2018 (4) (17)
Other April 2018–March 2022   3,894
      (20,751)
Net cash collateral provided     15,501
Net commodity derivative liability     $(5,250)
ContractsSettlement PeriodNet Long
(Short)
Notional Units
(in barrels)
Fair Value
of
Net Assets
(Liabilities)
(in thousands)
At March 31, 2022:
Crude oil fixed-price (1)April 2022–December 2023(1,330)$35,662 
Propane fixed-price (1)April 2022–December 2023184 3,785 
Refined products fixed-price (1)April 2022–December 2022685 (6,063)
Butane fixed-price (1)April 2022–December 2023(268)(1,711)
OtherApril 2022–March 202318,691 
50,364 
Net cash collateral provided839 
Net commodity derivative asset$51,203 
At March 31, 2021:
Crude oil fixed-price (1)April 2021–December 2023(1,850)$(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)
OtherApril 2021–June 202212,563 
7,501 
Net cash collateral provided8,203 
Net commodity derivative asset$15,704 
(1)
(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.
(2)We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

Amounts in the table above do not include commodity derivative contract positions related to our former Retail Propane segment, as these amounts have been classified as assets held for sale within our March 31, 2018 consolidated balance sheet (see
Note 17).

The following table summarizes the net (losses) gains (losses) recorded from our commodity derivatives to revenues and cost of sales in our consolidated statements of operations for the periods indicated (in thousands):
Year Ended March 31,
2022$(116,556)
2021$(83,578)
2020$85,941 
Year Ended March 31,  
2019 $33,631
2018 $(116,604)
2017 $(55,978)


Amounts in the table above do not include net losses(losses) gains from our commodity derivatives related to our former Retail Propane segment,Mid-Con, Gas Blending and TPSL as these amounts have been classified withinas discontinued operations within our consolidated statements of operations for the years ended March 31, 2021 and 2020 (see Note 17)18).


F-47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


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 March 31, 2019,2022, 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 consolidated balance sheets and recognized in our net income.

F-36

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Interest Rate Risk

The Revolving CreditABL Facility is variable-rate debt with interest rates that are generally indexed to bankthe Wall Street Journal prime rate or LIBOR interest rates.rate (or successor rate, which has since been determined to be SOFR). At March 31, 2019,2022, we had $1.2 billion$116.0 million of outstanding borrowings under the Revolving CreditABL Facility at a weighted average interest rate of 4.39%4.64%.

In addition, on and after certain dates, distributions for our Class B Preferred Units and Class C Preferred Units will be calculated using the applicable three-month LIBOR interest rate (or alternative rate as determined in accordance with the partnership agreement) plus a spread (see Note 9 for a further discussion).

Fair Value of Fixed-Rate Notes

The following table provides fair values estimates of our fixed-rate notes at March 31, 20192022 (in thousands):
Senior Secured Notes:
2026 Senior Secured Notes$2,016,688 
Senior Unsecured Notes:
2023 Notes$455,485 
2025 Notes$329,984 
2026 Notes$290,298 
Senior Unsecured Notes: 
2023 Notes$626,621
2025 Notes$375,126


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 12 in the fair value hierarchy.

Note 11—Segments
Note 12—Segments

The following table summarizes revenues relatedOur operations are organized into 3 reportable segments: (i) Water Solutions, (ii) Crude Oil Logistics and (iii) Liquids Logistics, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Liquids Logistics reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Operating income of these segments is reviewed by the chief operating decision maker to our segments. Revenues for reporting periods beginning after April 1, 2018 are presented under Topic 606 (see Note 15 for a further discussion), while prior periods are not adjustedevaluate performance and continue to be reported under the accounting standard in effect for those periods. Transactions between segmentsmake business decisions. Intersegment transactions are recorded based on prices negotiated between the segments and are eliminated upon consolidation.

See Note 1 for a discussion of the products and services of our reportable segments. The remainder of our business operations is presented as “Corporate and Other” category in the table below includesand consists of certain corporate expenses that are not allocated to the reportable segments. The following table below does not include amountssummarizes revenues related to our former Retail Propane segment, as these amounts have been classified within discontinued operations within our consolidated statements of operations (see Note 17).


segments for the periods indicated:
F-48
F-37

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Year Ended March 31,
202220212020
(in thousands)
Revenues:
Water Solutions:
Topic 606 revenues
Disposal service fees$409,548 $317,640 $330,877 
Sale of recovered crude oil77,203 28,599 59,445 
Sale of water39,518 13,569 12,381 
Other service revenues18,597 11,178 19,356 
Total Water Solutions revenues544,866 370,986 422,059 
Crude Oil Logistics:
Topic 606 revenues
Crude oil sales2,432,393 1,574,699 2,383,812 
Crude oil transportation and other75,484 142,233 170,138 
Non-Topic 606 revenues8,687 11,355 13,991 
Elimination of intersegment sales(11,068)(6,651)(18,174)
Total Crude Oil Logistics revenues2,505,496 1,721,636 2,549,767 
Liquids Logistics:
Topic 606 revenues
Refined products sales1,899,761 1,123,963 2,399,642 
Propane sales1,322,210 1,023,479 842,400 
Butane sales861,998 516,358 562,053 
Other product sales551,841 373,707 484,373 
Service revenues8,781 22,270 37,938 
Non-Topic 606 revenues254,285 79,442 289,713 
Elimination of intersegment sales(1,323)(6,073)(4,983)
Total Liquids Logistics revenues4,897,553 3,133,146 4,611,136 
Corporate and Other:
Non-Topic 606 revenues— 1,255 1,038 
Total Corporate and Other revenues— 1,255 1,038 
Total revenues$7,947,915 $5,227,023 $7,584,000 

The following table summarizes depreciation and amortization expense (including amortization expense recorded within interest expense, cost of sales and operating expenses in Note 6and Note 7) and operating income (loss) by segment for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Depreciation and Amortization:
Water Solutions$214,805 $222,354 $163,874 
Crude Oil Logistics48,489 60,874 70,759 
Liquids Logistics19,000 29,503 28,279 
Corporate and Other23,914 18,469 13,936 
Total$306,208 $331,200 $276,848 
Operating Income (Loss):
Water Solutions$94,851 $(92,720)$(173,064)
Crude Oil Logistics45,033 (304,330)117,768 
Liquids Logistics(8,441)70,441 142,411 
Corporate and Other(48,400)(64,144)(90,447)
Total$83,043 $(390,753)$(3,332)

F-38
  Year Ended March 31,
  2019 2018 (1) 2017 (1)
  (in thousands)
Revenues:      
Crude Oil Logistics:      
Topic 606 revenues      
Crude oil sales $3,011,355
 $2,151,203
 $1,603,667
Crude oil transportation and other 148,738
 122,786
 70,027
Non-Topic 606 revenues 12,598
 
 
Elimination of intersegment sales (36,056) (13,914) (6,810)
Total Crude Oil Logistics revenues 3,136,635
 2,260,075
 1,666,884
Water Solutions:      
Topic 606 revenues      
Disposal service fees 217,545
 149,114
 110,049
Sale of recovered hydrocarbons 72,678
 58,948
 31,103
Freshwater revenues 2,404
 
 
Other service revenues 9,017
 21,077
 18,449
Non-Topic 606 revenues 42
 
 
Total Water Solutions revenues 301,686
 229,139
 159,601
Liquids:      
Topic 606 revenues      
Propane sales 1,169,117
 1,203,486
 807,172
Butane sales 628,063
 562,066
 391,265
Other product sales 592,889
 432,570
 308,031
Service revenues 26,655
 22,548
 32,648
Non-Topic 606 revenues 21,608
 
 
Elimination of intersegment sales (23,291) (4,685) (1,944)
Total Liquids revenues 2,415,041
 2,215,985
 1,537,172
Refined Products and Renewables:      
Topic 606 revenues      
Refined products sales 5,455,204
 11,827,222
 8,884,976
Renewables sales 
 373,669
 447,232
Service fees and other revenues 498
 300
 10,963
Non-Topic 606 revenues 12,706,481
 
 
Elimination of intersegment sales 
 (268) (469)
Total Refined Products and Renewables revenues 18,162,183
 12,200,923
 9,342,702
Corporate and Other      
Non-Topic 606 revenues 1,362
 1,174
 844
Total Corporate and Other revenues 1,362
 1,174
 844
Total revenues $24,016,907
 $16,907,296
 $12,707,203
(1)We adopted ASC 606 as of April 1, 2018. Revenue reported in fiscal years 2018 and 2017 has not been changed from its previous presentation.


F-49

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



The following table summarizes depreciation and amortization expense and operating income (loss) by segment for the periods indicated.
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Depreciation and Amortization:      
Crude Oil Logistics $74,165
 $80,387
 $54,144
Water Solutions 108,162
 98,623
 101,758
Liquids 25,997
 24,937
 19,163
Refined Products and Renewables 1,518
 1,294
 1,562
Corporate and Other 3,018
 3,779
 3,612
Total depreciation and amortization (1) $212,860
 $209,020
 $180,239
       
Operating Income (Loss):      
Crude Oil Logistics $(7,379) $122,904
 $(17,475)
Water Solutions 210,525
 (24,231) 44,587
Liquids (2,910) (93,113) 43,252
Refined Products and Renewables 27,459
 56,740
 222,546
Corporate and Other (85,706) (79,474) (86,985)
Total operating income (loss) $141,989
 $(17,174) $205,925
(1)Amounts do not include amortization expense recorded within interest expense and cost of sales (see Note 7 and Note 8).

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. This information below does
Year Ended March 31,
202220212020
(in thousands)
Water Solutions$115,267 $66,649 $2,076,866 
Crude Oil Logistics6,422 9,933 28,828 
Liquids Logistics11,185 31,172 19,753 
Corporate and Other2,148 11,953 7,968 
Total$135,022 $119,707 $2,133,415 

All of the tables above do not include goodwill by segment.amounts related to Mid-Con, Gas Blending and TPSL, as these amounts have been classified as discontinued operations within our consolidated statements of operations for the years ended March 31, 2021 and 2020 (see Note 18).
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Crude Oil Logistics $28,039
 $36,762
 $168,053
Water Solutions 567,637
 102,261
 109,008
Liquids 72,717
 25,023
 66,864
Refined Products and Renewables 14,613
 
 42,175
Corporate and Other 1,819
 1,472
 2,825
Total $684,825
 $165,518
 $388,925


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:
March 31,
20222021
(in thousands)
Long-lived assets, net:
Water Solutions$2,970,911 $3,104,450 
Crude Oil Logistics1,050,546 1,090,578 
Liquids Logistics (1)385,783 626,221 
Corporate and Other49,067 44,802 
Total$4,456,307 $4,866,051 
  March 31,
  2019 2018
  (in thousands)
Long-lived assets, net:    
Crude Oil Logistics $1,584,636
 $1,638,558
Water Solutions 1,600,836
 1,256,143
Liquids (1) 498,767
 501,302
Refined Products and Renewables 217,881
 208,849
Corporate and Other 26,569
 31,516
Total $3,928,689
 $3,636,368
(1)    Includes $17.1 million and $20.9 million of non-US long-lived assets at March 31, 2022 and 2021, respectively.

March 31,
20222021
(in thousands)
Total assets:
Water Solutions$3,130,659 $3,204,850 
Crude Oil Logistics1,952,048 1,665,005 
Liquids Logistics (1)888,927 1,003,370 
Corporate and Other98,711 74,116 
Total$6,070,345 $5,947,341 
(1)    Includes $40.2 million and $37.9 million of non-US total assets at March 31, 2022 and 2021, respectively.

F-50
F-39

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Note 12—Transactions with Affiliates

The following table summarizes our related party transactions for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Sales to entities affiliated with management$— $18,402 $8,367 
Purchases from entities affiliated with management$1,489 $1,239 $3,799 
Sales to equity method investees$— $— $203 
Purchases from equity method investees$1,091 $3,249 $2,120 
Sales to WPX (1)$39,129 $48,222 
Purchases from WPX (1)$216,487 $313,578 
Sales to SemGroup (2)$458 
(1)    As previously disclosed, 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.
(2)    As previously disclosed, SemGroup Corporation (“SemGroup”), who holds ownership interests in our general partner, was acquired by Energy Transfer LP (“ET”) in December 2019. During the three months ended December 31, 2019, we reevaluated our related parties and determined that SemGroup/ET no longer meet the criteria to be disclosed as a related party. Therefore, information for the six months ended September 30, 2019 has been retained but we have not disclosed any information related to transactions subsequent to September 30, 2019.

Accounts receivable from affiliates consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
NGL Energy Holdings LLC$8,483 $8,245 
Equity method investees107 462 
Entities affiliated with management728 
Total$8,591 $9,435 

Accounts payable to affiliates consist of the following at the dates indicated:
March 31,
20222021
(in thousands)
Equity method investees$27 $107 
Entities affiliated with management46 12 
Total$73 $119 

Other Related Party Transactions

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

In connection with the purchase of our 50% interest in an aircraft company, KAIR2014, discussed below, we executed a joint and several guarantee for the benefit of the lender for KAIR2014’s outstanding loan. The other owner of KAIR2014, our Chief Executive Officer, H. Michael Krimbill, 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 March 31, 2022, the outstanding balance of the loan is approximately $2.5 million. Payments are made monthly, reducing the outstanding balance, 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 March 31, 2022, 0 accrual has been recorded related to this guarantee.

F-40

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


(1)Includes $0.5 million and $0.6 million of non-US long-lived assets at March 31, 2019 and 2018, respectively.

  March 31,
  2019 2018
  (in thousands)
Total assets:    
Crude Oil Logistics $2,237,612
 $2,285,813
Water Solutions 1,668,292
 1,323,171
Liquids (1) 721,008
 717,690
Refined Products and Renewables 1,198,562
 1,204,633
Corporate and Other 77,019
 102,211
Assets held for sale 
 517,604
Total $5,902,493
 $6,151,122
(1)Includes $12.0 million and $27.5 million of non-US total assets at March 31, 2019 and 2018, respectively.

Note 13—Transactions with Affiliates

A member of the board of directors of our general partner is an executive officer of WPX Energy, Inc. (“WPX”). We purchase crude oil from and sell crude oil to WPX (certain of the purchases and sales that were entered into in contemplation of each other are recorded on a net basis within revenues in our consolidated statement of operations). We also treat and dispose of wastewater and solids received from WPX.

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

We purchased ethanol from E Energy Adams, LLC, in which we previously held an ownership interest as an equity method investee. We sold our interest in E Energy Adams, LLC on May 3, 2018 (see Note 2). These transactions are reported within cost of sales in our consolidated statements of operations.

The following table summarizes these related party transactions for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Sales to WPX $28,026
 $
 $
Purchases from WPX (1) $329,525
 $
 $
Sales to SemGroup $1,114
 $606
 $3,866
Purchases from SemGroup $4,395
 $5,034
 $12,254
Sales to entities affiliated with management $21,385
 $268
 $290
Purchases from entities affiliated with management $4,382
 $3,870
 $15,209
Sales to equity method investees $
 $294
 $692
Purchases from equity method investees $
 $66,820
 $121,336

(1)Amount primarily relates to purchases of crude oil under the definitive agreement we signed with WPX, as discussed further below.


F-51

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Accounts receivable from affiliates consist of the following at the dates indicated:
  March 31,
  2019 2018
  (in thousands)
Receivables from NGL Energy Holdings LLC $7,277
 $4,693
Receivables from WPX 5,185
 
Receivables from SemGroup 71
 49
Receivables from entities affiliated with management 334
 24
Receivables from equity method investees 
 6
Total $12,867
 $4,772


Accounts payable to affiliates consist of the following at the dates indicated:
  March 31,
  2019 2018
  (in thousands)
Payables to WPX $27,844
 $
Payables to entities affiliated with management 625
 1,246
Payables to equity method investees 
 8
Total $28,469
 $1,254


Other Related Party Transactions

Victory Propane

On August 14, 2018, we sold our 50% interest in Victory Propane to Victory Propane, LLC. As consideration, we received a promissory note in the amount of $3.4 million, which encompassed the purchase price for our 50% interest plus the outstanding balance of the loan receivable of $2.6 million as of the date of the transaction. The promissory note bears no interest and matures on July 31, 2023. We discounted the promissory note to its net present value of $2.6 million, with the amount of the reduction in the value of the promissory note recorded as a loss within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations. This was the final transaction in exiting the retail propane business and was considered to be inconsequential by management. As a result of the sale, Victory Propane is no longer considered a related party.

At March 31, 2018, we had a loan receivable from Victory Propane, an equity method investee at the time (see Note 2), of $1.2 million.

During the three months ended December 31, 2017 we completed a transaction with Victory Propane, an equity method investee at the time (See Note 2), to purchase Victory Propane’s Michigan assets. We paid Victory Propane $6.4 million in cash and received current assets, property, plant and equipment and customers. The allocation of the consideration was as follows (in thousands):
Current assets$276
Property, plant and equipment1,366
Intangible assets (customer relationships)4,782
Fair value of net assets acquired$6,424


Victory Propane recognized a gain on this transaction. As all intra-entity profits and losses are eliminated between an investor and investee until realized, we eliminated our proportionate share of the gain from this transaction on our books. As a result, our underlying equity in the net assets of Victory Propane exceeded our investment (see Note 2), and this difference was amortized as income over the remaining life of the noncurrent assets acquired until they were sold on August 14, 2018. As the sale of virtually all of our remaining Retail Propane segment to Superior (see Note 1) included Victory Propane’s Michigan assets, we were able to recognize our proportionate share of the gain recognized by Victory Propane. As a result, we were able to reverse our proportionate share of their losses that had been recorded against the balance of the loan receivable and write up the value of our investment in Victory Propane to $0.8 million.

F-52

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Agreement with WPX

During the three months ended June 30, 2018,2019, we entered intopurchased a definitive agreement with WPX. Under this agreement,50% interest in KAIR2014 for $0.9 million in cash and accounted for our interest using the equity method of accounting (see Note 2). The remaining interest in KAIR2014 is owned by our Chief Executive Officer, H. Michael Krimbill.

2026 Senior Secured Notes and ABL Facility

To complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 7), we agreedwere required to provide WPXreceive the benefitconsent of the holders of our minimum shipping fees or deficiency credits (fees paid in previous periods that were in excess of the volumes actually shipped) totaling $67.7 million at the time of the transaction (as discussed further in Note 2), which can be utilized for volumes shipped that exceed the minimum monthly volume commitment in subsequent periods. As a result, we wrote-off these minimum shipping fees previously included within other noncurrent assets in our consolidated balance sheet (see Note 2) and recorded a loss within loss (gain) on disposal or impairment of assets, net. We also agreed that we would only ship crude oil that weClass D Preferred Units, who are required to purchase from WPX in utilizing our allotted capacity on these pipelines and they agreed to be fully responsible to us for all deficiency payments (money due when our actual shipments are less than our allotted capacity) for the remaining term of our contract, which totaled $50.3 million at June 30, 2018 (as discussed further in Note 9). As consideration for this transaction, we paid WPX a net $35.3 million, which was recorded as a loss within loss (gain) on disposal or impairment of assets, net.

Repurchase of Warrants

On April 26, 2018 and June 23, 2017, we repurchased outstanding warrants, as discussed further in Note 10, from funds managed by Oaktree, who were represented on the board of directors of our general partner (see Note 19).partner. For their consent, we paid to the holders of the Class D Preferred Units $40.0 million.


Acquisition of Interest in NGL Energy Holdings LLC
Grassland

We previously hadDuring the year ended March 31, 2020, we purchased, in 3 transactions, a loan receivable from Grassland Water Solutions, LLC (“Grassland”) and during the three months ended June 30, 2016, we received loan payments of $0.7 million from Grassland in accordance with the loan agreement. On June 3, 2016, we acquired the remaining 65% ownership2.97% interest in Grassland. Prior to the completion of this transaction, weour general partner, NGL Energy Holdings LLC, for $3.8 million in cash and accounted for our previously held 35% ownership interest in Grassland using thethis as a deduction within limited partners’ equity method of accounting. As we owned a controlling interest in Grassland, we revalued our previously held 35% ownership interest to fair value of $0.8 million and recorded a loss of $14.9 million. As the amount paid (cash plus the fair value of our previously held ownership interest) was less than the fair value of the assets acquired and liabilities assumed, we recorded a bargain purchase gain of $0.6 million. Once we acquired the remaining ownership interest in Grassland, the loan receivable was eliminated as Grassland was consolidated in our consolidated financial statements. Asbalance sheet. We also purchased a result of the acquisition, we incurred an impairment charge of $1.75.73% interest in our general partner, NGL Energy Holdings LLC, for $11.5 million to write down the loan receivable to its fair value, which was reportedin cash and accounted for this as a deduction within loss (gain) on disposal or impairment of assets, netlimited partners’ equity in our consolidated statementbalance sheet. This interest was purchased from a fund controlled by The Energy & Minerals Group, which is represented on the board of operations. On November 29, 2016, we sold Grassland and received proceedsdirectors of $22.0 million and recorded a loss on disposal of $2.3 million during the three months ended December 31, 2016. This loss is reported within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations.general partner.

Note 14—13—Employee Benefit Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. For every dollar that employees contribute up to 1% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employees contribute between 1% and 6% of their eligible compensation (as defined in the plan). Our matching contributions priorvest over an employee’s first two years of employment, subject to a participant’s continued service. Effective January 1, 2015 vest over five years2020, for every dollar that employees contribute up to 4% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employees contribute between 4% and effective January 1, 2015, our matching contributions vest over two years.6% of their eligible compensation (as defined in the plan). Expenses under the plan for the years ended March 31, 2019, 20182022, 2021 and 20172020 were $2.0$3.9 million, $1.8$3.4 million and $1.9$2.3 million, respectively. Expensesrespectively, and do not include expenses for matching contributions related to our former Retail Propane segmentMid-Con, Gas Blending and TPSL which have been classified withinas discontinued operations within our consolidated statements of operations (see Note 17).

Note 15—Revenue from Contracts with Customers

Impact of Adoption

We adopted ASC 606 on April 1, 2018, using the modified retrospective method. Revenues for reporting periods beginning after April 1, 2018 are presented under Topic 606, while prior periods are not adjusted and continue to be reported under the accounting standard in effect for those periods. We recorded an increase to the beginning balance of equity as of April 1, 2018, due to the cumulative impact of adopting the standard, as discussed further below.

Based on our evaluation, we anticipate that from time to time, differences in the timing of revenues earned and our right to invoice customers may create contract assets or liabilities. These differences in timing would be the result of contracts

F-53

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


that contain minimum volume commitments and tiered pricing provisions, primarily within our Water Solutions segment. In addition, we completed the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under this standard. Furthermore, under this standard we made an accounting policy election to exclude from the measurement of the transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that we collect from a customer.

As discussed previously, we sold our general partner interest in TransMontaigne Partners L.P. (“TLP”) and deferred a portion of the gain related to the sale of which the current portion was recorded in accrued expenses and other payables and the long-term portion was recorded in other noncurrent liabilities at March 31, 2018 within our consolidated balance sheet. During the years ended March 31, 20182021 and 2017, we recognized $30.1 million and $30.1 million, respectively, of the deferred gain in our consolidated statements of operations. As this transaction was accounted for under the real estate guidance in ASC 360-20, Property, Plant and Equipment, wehad been amortizing the gain over the life of the related lease agreements. Upon adoption of ASC 606, we determined that this transaction should be accounted for under the guidance of ASC 810-10-40 and utilizing the modified retrospective approach of adoption, the deferred gain as of March 31, 2018 of $139.3 million was recognized in the beginning balance of retained earnings as part of our cumulative effect adjustment at April 1, 2018.2020 (see Note 18).

The following tables summarize the impact of adoption on our consolidated balance sheet at March 31, 2019 and our consolidated statements of operations for the year ended March 31, 2019:
  Consolidated Balance Sheet
  March 31, 2019
  As Reported Balances Without Adoption of ASC 606 Effect of Change
Increase/(Decrease)
  (in thousands)
Accrued expenses and other liabilities $248,450
 $278,563
 $(30,113)
Other noncurrent liabilities $63,575
 $142,656
 $(79,081)
Equity:      
General partner $(50,603) $(50,712) $109
Limited partners $2,067,197
 $1,958,113
 $109,084
  Consolidated Statement of Operations
  March 31, 2019
  As Reported Balances Without Adoption of ASC 606 Effect of Change
Increase/(Decrease)
  (in thousands)
Loss on disposal or impairment of assets, net $34,296
 $4,183
 $30,113
Operating income $141,989
 $172,102
 $(30,113)
Net income $339,395
 $369,508
 $(30,113)


Prior to April 1, 2018, we recognized revenue for services and products when all of the following criteria were met under Topic 605: (i) either services have been rendered or products have been delivered or sold; (ii) persuasive evidence of an arrangement existed; (iii) the price for services was fixed or determinable; and (iv) collectibility was reasonably assured. We recorded deferred revenue when we received amountsNote 14—Revenue from our customers but had not yet met the criteria listed above. We recognized deferred revenue in our consolidated statement of operations when the criteria had been met and all services had been rendered.Contracts with Customers

Effective April 1, 2018, weWe 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. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer. A contract’s transaction price is allocated to each distinct performance obligation in the contract and is recognized as revenue when, or as, the performance obligation is satisfied. Our revenue contracts in scope under ASC 606 primarily have a single performance obligation. The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgment and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers and the relative stand-alone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can vary from those judgments and assumptions. We do not

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


have any material contracts with multiple performance obligations or under which we receive material amounts of non-cash consideration at March 31, 2018.consideration. Our costs to obtain or fulfill our revenue contracts were not material as of March 31, 2019.

2022.

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 840,842, respectively. See Note 1211 for a detail of disaggregated revenue. Revenue from contracts accounted for as derivatives under ASC 815 within our Refined and RenewablesLiquids Logistics segment includes $75.5$2.4 million of net lossesgains related to changes in the mark-to-market value of these arrangements recorded during the year ended March 31, 2019.2022.

Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days. In instances where the timing of revenue recognition differs from the timing of invoicing, we have determined our contracts generally do not include a significant financing component. The primary purpose of our invoicing terms is to allow customers to secure the right to reserve the product or storage capacity to be received or used at a later date, not to receive financing from our customers or to provide customers with financing.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

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

Water Solutions Performance Obligations

Within the Water Solutions segment, revenue is disaggregated into two primary revenue streams that include service revenue and commodity sales revenue. For contracts involving disposal services, we accept produced water and solids for disposal at our facilities. In cases where we have agreed within a contract or are required by law to remove crude oil from the produced water, the skim oil will be valued as non-cash consideration. Ordinarily, it is required that the fair value of the skim oil is to be estimated at contract inception; however, due to variability of the form of the non-cash consideration, the amount and dollar value is unknown at the contract inception date. Accordingly, ASC 606-10-32-11 allows us to value the skim oil on the date in which the value becomes known.

The Water Solutions segment has certain disposal contracts that contain the following types of terms or pricing structures that involve significant judgment that impacts the determination and timing of revenue.

Minimum volume commitments. We receive a shortfall fee if the customer does not deliver a certain amount of volume of produced water over a specified period of time. At each reporting period, we make a determination as to the likelihood of earning this fee. We recognize revenue from these contracts when (i) actual volumes are received; and (ii) when the likelihood of a customer exercising its remaining rights to make up the deficient volumes under minimum volume commitments becomes remote (also known as the breakage model).
Tiered pricing. For contracts with tiered pricing provisions, the period in which the tiers are earned and settled (i.e. the “reset period”) may vary from monthly to over a period of multiple months. If the tiered pricing is based on a month, we allocate the fee to the distinct daily service to which it relates. If the tiered pricing spans across multiple reporting periods, we estimate the total transaction price at the beginning of each reset period, based on the expected volumes. We revise the estimate of variable consideration at each reporting date throughout each reset period.
Volume discount pricing. Volume discount pricing is a form of variable consideration whereby the customer pays for the volumes delivered on a cumulative basis. Similar to tiered pricing, the period in which the cumulative volumes are earned and settled (i.e. the “reset period”) may vary from daily to over a period of multiple months. If the volume discount is based on a month, we allocate the fee to the distinct daily service to which it relates. If the volume discount period spans across multiple reporting periods, we estimate the total transaction price at the beginning of each reset period, based on the expected volumes. We revise the estimate of variable consideration at each reporting date throughout each reset period.

For all of our disposal contracts within the Water Solutions segment, revenue will be recognized over time utilizing the output method based on the volume of produced water or solids we accept from the customer. For contracts that involve the sale of recovered crude oil and reuse, recycled and brackish non-potable water, we will recognize revenue at a point in time, based on when control of the product is transferred to the customer.

Crude Oil Logistics Performance Obligations

Within the Crude Oil Logistics segment, revenue is disaggregated into two primary revenue streams that include revenue from the sale of commodities and service revenue. For sales of commodities, we are obligated to deliver a predetermined amount of productcrude oil, primarily on a month-to-month basis, to our customers. For these types of agreements, revenue is recognized at a point in time based on when the productcrude oil is delivered and control is transferred to the customer.

For revenue received from services rendered, we are obligated to provide throughput services to move productcrude oil via pipeline, truck, railcar, or marine vessel or to provide terminal maintenance services. In either case, the obligation is satisfied over time utilizing the output method based on each volume of productcrude oil that is moved from the origination point to the final destination or based on the passage of time.

Water SolutionsLiquids Logistics Performance Obligations

Within the Water Solutions segment, revenue is disaggregated into two primary revenue streams that include service revenue and commodity sales revenue. For contracts involving disposal services, we accept wastewater and solids for disposal at our facilities. In cases where we have agreed within a contract or are required by law to remove hydrocarbons from the wastewater, the skim oil will be valued as non-cash consideration. Ordinarily, it is required that the fair value of the skim oil is to be estimated at contract inception; however, due to variability of the form of the non-cash consideration, the amount and dollar value is unknown at the contract inception date. Accordingly, ASC 606-10-32-11 allows us to value the skim oil on the date in which the value becomes known.

The Water Solutions segment has certain disposal contracts that contain the following types of terms or pricing structures that involve significant judgment that impacts the determination and timing of revenue.

Minimum volume commitments. We receive a shortfall fee if the customer does not deliver a certain amount of volume of wastewater over a specified period of time. At each reporting period, we make a determination as to the likelihood of earning this fee. We recognize revenue from these contracts when (i) actual volumes are received; and (ii) when the likelihood of a customer exercising its remaining rights to make up the deficient volumes under minimum volume commitments becomes remote (also known as the breakage model).
Tiered pricing. For contracts with tiered pricing provisions, the period in which the tiers are earned and settled (i.e. the “reset period”) may vary from monthly to over a period of multiple months. If the tiered pricing is based on a month, we allocate the fee to the distinct daily service to which it relates. If the tiered pricing spans across multiple reporting periods, we estimate the total transaction price at the beginning of each reset period, based on the expected volumes. We revise our estimates of variable consideration at each reporting date throughout each reset period.
Volume discount pricing. Volume discount pricing is a form of variable consideration whereby the customer pays for the volumes delivered on a cumulative basis. Similar to tiered pricing, the period in which the cumulative volumes are earned and settled (i.e. the “reset period”) may vary from daily to over a period of multiple months. If

F-55

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


the volume discount is based on a month, we allocate the fee to the distinct daily service to which it relates. If the volume discount period spans across multiple reporting periods, we estimate the total transaction price at the beginning of each reset period, based on the expected volumes. We revise the estimate of variable consideration at each reporting date.

For all of our disposal contracts within the Water Solutions segment, revenue will be recognized over time utilizing the output method based on the volume of wastewater or solids we accept from the customer. For contracts that involve the sale of recovered hydrocarbons and freshwater, we will recognize revenue at a point in time, based on when control of the product is transferred to the customer.

Liquids Performance Obligations

Within the Liquids Logistics segment, revenue is disaggregated into two primary revenue streams that include revenue from the sale of commodities and providing services.service revenue. For commodity sales of commodities, we are obligated to deliver a specified amount of
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

product over a specified period of time. For these types of agreements, revenue is recognized at a point in time based on when the product is delivered and control is transferred to the customer.

For revenue received from services rendered, we offer a variety of services which include: (i) storage services where product is commingled; (ii) railcar transportation services; (iii) transloading services; and (iv) logistics services. We are obligated to provide these services over a predetermined period of time. Revenue from service contracts is recognized at a point in time upon the transfer of control each month. All revenue from services is recognized over time utilizing the output method based on volumes stored or moved.

Refined Products and Renewables Performance Obligations

The Refined Products and Renewables segment has one distinct revenue stream, which is revenue from commodity sales. In these agreements, we are obligated to sell a predetermined amount of product over a specified period of time. Revenue for all commodity sales is recognized at a point in time once the customer has lifted the agreed-upon volumes.

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 utilizingutilized 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 March 31, 20192022 (in thousands):
Year Ending March 31,
2023$117,792 
202496,205 
202573,224 
202617,240 
20273,727 
Thereafter2,071 
Total$310,259 
Fiscal Year Ending March 31, 
2020$167,061
2021128,572
2022119,016
2023113,861
202499,430
Thereafter242,032
Total$869,972


Many agreements are short-term in nature with a contract term of one year or less. For those contracts, we utilized the practical expedient in ASC 606-10-50 that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, for our product sales contracts, we have elected the practical expedient set out in ASC 606-10-50-14A, which states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these agreements, each unit of product represents a separate performance obligation and therefore future volumes are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligations is not required. Under product sales contracts, the variability arises as both volume and pricing (typically index-based) are not known until the product is delivered.


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Contract Assets and Liabilities

Amounts owed from our customers under our revenue contracts are typically billed as the service is being provided on a monthly basis and are due within 1-30 days of billing, and are classified as accounts receivable-trade on our consolidated balance sheets. Under certain of our contracts, we recognize revenues in excess of billings, referred to as contract assets, within prepaid expenses and other current assets in our consolidated balance sheets. Accounts receivable from contracts with customers are presented within accounts receivable-trade and accounts receivable-affiliates in our consolidated balance sheets. Our contract asset balances primarily relate to our underground cavern storage contracts with multi-period contracts in which the fee escalates each year and the customer provides upfront payment at the beginning of the contract period. We did not record any contract assets during this period.the year ended March 31, 2022.

Under certain of our contracts we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized, referred to as deferred revenue or contract liabilities, within advance payments received from customers in our consolidated balance sheets. Our deferred revenue primarily relates to:

Prepayments. Some revenue contracts contain prepayment provisions within our Liquids segment. Revenue received related to our underground cavern storage services is received upfront at the beginning of the contract period and is deferred until services have been rendered. In some cases, we also receive prepayments from customers purchasing commodities, which allows the customer to secure the right to receive their requested volumes in a future period. Revenue from these contracts is initially deferred, thus creating a contract liability.
Multi-period contract in which fee escalates each subsequent year of the contract. Revenue from these contracts is recognized over time based on a weighted average of what is expected to be received over the life of the contract. As the actual amount billed and received from the customer differs from the amount of revenue recognized, a contract liability is recorded.
Tiered pricing and volume discount pricing. As described above, we revise our estimates of variable consideration at each reporting date throughout each reset period. As the actual amount billed and received from the customer differs from the amount of revenue recognized, a contract liability is recorded.
Capital reimbursements. Certain contracts in our Water Solutions segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets, such as water gathering pipelines and custody transfer points, utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract.

The following tables summarizes the balances of our contract assets and liabilities at the dates indicated (in thousands):
  Balance at
  April 1, 2018 March 31, 2019
Accounts receivable from contracts with customers $677,095
 $740,878
Contract liabilities balance at April 1, 2018 $8,374
Payment received and deferred 77,956
Payment recognized in revenue (77,409)
Contract liabilities balance at March 31, 2019 $8,921


Prepayments. Some revenue contracts contain prepayment provisions within our Liquids Logistics segment. In some cases, we also receive prepayments from customers purchasing commodities, which allows the customer to secure the right to receive their requested volumes in a future period. Revenue from these contracts is initially deferred, thus creating a contract liability.
Note 16—Other MattersMulti-period contract in which fee escalates each subsequent year of the contract. Revenue from these contracts is recognized over time based on a weighted average of what is expected to be received over the life of the contract. As the actual amount billed and received from the customer differs from the amount of revenue recognized, a contract liability is recorded.

Sale of South Pecos Water Disposal Business

On February 28, 2019, we completed the sale of our South Pecos water disposal business to a subsidiary of WaterBridge Resources LLC for $232.2 million in net cash proceeds and recorded a gain on disposal of $107.9 million during the year ended March 31, 2019. This gain is reported within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations. These operations include: (i) nine saltwater disposal facilities, (ii) all disposal agreements, commercial, surface and other contracts related to those facilities, (iii) pipelines connected to the facilities and (iv) several

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


disposal permits. All of the assets sold in this transaction are located near the town of Pecos, Texas in southern ReevesTiered pricing and Ward counties. WaterBridge Resources LLC also has the option to acquire additional land and permits once the permitting process has been completed.

volume discount pricing. As this sale transaction did not representdescribed above, we revise the estimate of variable consideration at each reporting date throughout each reset period. As the actual amount billed and received from the customer differs from the amount of revenue recognized, a strategic shift that will have a major effect on our operations or financial results, operations related to this portion ofcontract liability is recorded.
Capital reimbursements. Certain contracts in our Water Solutions segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets, such as water gathering pipelines and custody transfer points, utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract.

Contract Assets and Liabilities

The following tables summarize the balances of our contract assets and liabilities at the dates indicated:
March 31, 2022March 31, 2021
(in thousands)
Accounts receivable from contracts with customers$605,384 $436,682 
Contract liabilities balance at March 31, 2021$10,896 
Payment received and deferred49,024 
Payment recognized in revenue(44,019)
Disposition of Sawtooth (see Note 17)(8,234)
Contract liabilities balance at March 31, 2022$7,667 

Note 15—Leases

We adopted ASC 842 effective April 1, 2019 using the modified retrospective method with no cumulative effect adjustment to equity. Upon adoption, we recorded operating lease right-of-use assets of $551.2 million and operating lease obligations of $549.0 million, including amounts classified as assets and liabilities held for sale as of April 1, 2019. The adoption of this standard did not impact our unaudited condensed consolidated statement of operations or unaudited condensed consolidated statement of cash flows for the three months ended June 30, 2019.

We also elected the following transitional practical expedients, which allowed us to (i) not evaluate land easements prior to April 1, 2019; (ii) use hindsight in determining the lease term; (iii) not reassess whether current or expired contracts contain leases; (iv) not reassess the lease classification for any expired or existing leases; and (v) not reassess initial costs.

Lessee Accounting

Our leasing activity primarily consists of product storage, office space, real estate, railcars, and equipment. We determine if an agreement contains a lease at the inception of the arrangement. If an arrangement is determined to contain a lease, we classify the lease as an operating lease or a finance lease depending on the terms of the arrangement. All of our leases are classified as operating leases. Operating lease right-of-use assets represent our right to use an underlying asset for the lease term when we control the use of the asset by obtaining substantially all of the economic benefits of the asset and direct the use of the asset. Operating lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and operating lease liabilities with an initial term of greater than one year are recognized at the commencement date based on the present value of lease payments over the lease term. As our leases do not provide an implicit interest rate, we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Our incremental borrowing rate represents the interest rate which we would pay to borrow, on a collateralized basis, an amount equal to the lease payments over a similar term in a similar economic environment. We do not have any leases that provide for guarantees of residual value.

Our lease agreements may include options to extend or terminate the lease which are included in the measurement of our operating lease liability when it is reasonably certain that we will exercise the option. Lease renewal terms vary from one year to 30 years. Operating lease expense is recognized on a straight-line basis over the lease term. We have variable lease payments, including adjustments to lease payments based on an index or rate, such as a consumer price index, fair value adjustments to lease payments, and common area maintenance, real estate taxes, and insurance payments in certain real estate leases. We also have certain land leases within our Water Solutions segment that require us to pay a royalty, which could be
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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

based on a flat rate per barrel disposed or a percentage of revenue generated. Variable lease payments are excluded from operating lease right-of-use assets and operating lease liabilities and are expensed as incurred. Operating lease right-of-use assets also include any lease prepayments and exclude lease incentives. For leases acquired as a result of an acquisition, the right-of-use asset also includes adjustments for any favorable or unfavorable market terms present in the lease.

Short-term leases with an initial term of 12 months or less that do not include a purchase option, with the exception of railcar leases, are not recorded on the consolidated balance sheet. Operating lease expense for short-term leases is recognized on a straight-line basis over the lease term and is disclosed below.

We have lease agreements with lease and non-lease components, which are generally accounted for separately. For certain leases of buildings and land, we account for the lease and non-lease components as a single lease component based on the election of the practical expedient to not separate lease components from non-lease components.

At March 31, 2022, we had operating lease right-of-use assets of $114.1 million and current and noncurrent operating lease obligations of $41.3 million and $72.8 million, respectively, on our consolidated balance sheet. At March 31, 2021, we had operating lease right-of-use assets of $152.1 million and current and noncurrent operating lease obligations of $47.1 million and $103.6 million, respectively, on our consolidated balance sheet. At March 31, 2022, the weighted-average remaining lease term and weighted-average discount rate for our operating leases was 6.46 years and 7.49%, respectively. At March 31, 2021, the weighted-average remaining lease term and weighted-average discount rate for our operating leases was 6.88 years and 7.06%, respectively.

The following table summarizes the components of our lease expense for the periods indicated:
Year Ended March 31,
202220212020
(in thousands)
Operating lease expense$58,535 $69,031 $72,340 
Variable lease expense22,130 18,871 19,158 
Short-term lease expense351 1,217 799 
Total$81,016 $89,119 $92,297 

The following table summarizes maturities of our operating lease obligations at March 31, 2022 (in thousands):
Year Ending March 31,
2023$46,599 
202430,020 
202517,490 
20268,416 
20274,593 
Thereafter38,821 
Total lease payments145,939 
Less imputed interest(31,894)
Total operating lease obligations$114,045 

The following table summarizes supplemental cash flow and non-cash information related to our operating leases for the periods indicated:
Year Ended March 31,
202220212020 (1)
(in thousands)
Cash paid for amounts included in the measurement of operating lease obligations$57,449 $68,141 $101,678 
Operating lease right-of-use assets obtained in exchange for operating lease obligations$14,950 $33,579 $598,734 
(1)    Amounts include the leases and activity for TPSL and Gas Blending which were sold during the year ended March 31, 2020 (see Note 18).

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Lessor Accounting and Subleases

Our lessor arrangements include storage and railcar contracts, of which certain agreements contain renewal options for periods of between one year and five years. We determine if an agreement contains a lease at the inception of the arrangement. If an arrangement is determined to contain a lease, we classify the lease as operating, sales-type or direct financing. Lessor accounting under ASC 842 is substantially unchanged and all of our leases will continue to be classified as operating leases. 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 years ended March 31, 2022, 2021 and 2020, fixed rental revenue was $14.4 million, $15.9 million and $20.4 million, which includes $1.4 million, $2.5 million and $4.6 million of sublease revenue, respectively.

The following table summarizes future minimum lease payments receivable under various noncancelable operating lease agreements at March 31, 2022 (in thousands):
Year Ending March 31,
2023$8,947 
20244,807 
2025692 
2026415 
2027415 
Thereafter423 
Total$15,699 

Note 16—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.

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 expected credit loss allowance for accounts receivable - trade for the periods indicated:
Year Ended March 31,
202220212020 (1)
 (in thousands)
Balance at beginning of year$2,192 $4,540 $4,016 
Cumulative effect adjustment— 433 — 
Change in provision for expected credit losses929 319 1,202 
Write-offs charged against the provision(491)(3,100)(678)
Disposition of Sawtooth (See Note 17)(4)— — 
Balance at end of year$2,626 $2,192 $4,540 
(1)    We adopted ASU 2016-13 as of April 1, 2020. The allowance reported for the year ended March 31, 2020 has not been classifiedchanged from its previous presentation.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

The following table summarizes changes in our expected credit loss allowance for notes receivable and other for the periods indicated:
Year Ended March 31,
20222021 (1)
(in thousands)
Balance at beginning of year$458 $— 
Cumulative effect adjustment— 680 
Write-offs charged against the provision— (222)
Balance at end of year$458 $458 
(1)    We adopted ASU 2016-13 as discontinued operations.of April 1, 2020. An allowance had not been established for notes receivable and other prior to the adoption of ASU 2016-13.

Sale of Bakken Saltwater Disposal Business

On November 30, 2018,In addition to the provision for expected credit losses above, we completed the sale of NGL Water Solutions Bakken, LLC to an affiliate of Tallgrass Energy, LP for $85.0 million in net cash proceeds and recorded a gain on disposal of $33.4also wrote off $5.7 million during the year ended March 31, 20192021 as discussed in Note 17.

Note 17—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 (gain) on disposal or impairment of assets, net in our consolidated statement of operations. These operations include five saltwater disposal wells located in McKenzie and Dunn Counties, North Dakota.for the year endedMarch 31, 2022.

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 Water SolutionsLiquids Logistics segment have not been classified as discontinued operations.

Sawtooth Joint VentureThird-party Loan Receivable

On March 30, 2018,As previously disclosed, we completed the transaction to formhad an outstanding loan receivable of $26.7 million, including accrued interest, associated with our interest in a joint venture with Magnum Liquids, LLC, a portfolio company of Haddington Ventures LLC, along with Magnum Development, LLC and other Haddington-sponsored investment entities (collectively “Magnum”) to focus on the storage of natural gas liquids loading/unloading facility (the “Facility”) that was utilized by a third party. Our loan receivable was secured by title to and refined products by combininga lien interest on the Facility. The third party filed a petition for bankruptcy under Chapter 11 of the bankruptcy code in July 2019, at which time we filed our Sawtooth salt dome storage facilityProof of Claim within the bankruptcy case. On June 26, 2020, we settled our claim with Magnum’s refined products rightsthe third party and adjacent leasehold.Magnum acquired an approximately 28.5% interest in Sawtooth from us, in exchangeagreed to receive $16.3 million, for consideration consisting of a cash payment of approximately$37.6 million(excluding working capital) and the contribution of certain refined products rights and adjacent leasehold, which we valued at $21.6released any and all claims and/or liens with respect to the Facility and transferred title of the Facility to the third party. For the remaining $10.4 million of the loan receivable, we filed an unsecured claim within the bankruptcy. As of June 30, 2020, we wrote-off approximately $9.4 million, the portion of the unsecured claimed we have deemed uncollectible, and recorded within intangible assets in our consolidated balance sheet. The disposition of this interest was accounted for as an equity transaction, no gain or lossamount was recorded and the carrying value of the noncontrolling interest was adjusted to reflect the change in ownership interest of the subsidiary.We own approximately 71.5% of the joint venture; and within the nexttwoyears, Magnum has options to acquire our remaining interest for an additional $182.4 million.

Sale of Interest in Glass Mountain Pipeline, LLC (“Glass Mountain”)

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain for net proceeds of $292.1 million and recordedas a gain on disposal of $108.6 million during the three months ended December 31, 2017loss within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations.

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 Crude Oil Logistics segment have not been classified as discontinued operations.

Termination of a Storage Sublease Agreement

During the year ended March 31, 2017, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 20172022, the remaining balance of $0.6 million, net of an allowance for an expected credit loss, is recorded within prepaid expenses and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments which began in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain of $16.2 million to other (expense) income, netcurrent assets in our consolidated statement of operationsbalance sheet.

Third-party Bankruptcy

As previously disclosed, during the yearthree months ended March 31, 2017.

TerminationJune 30, 2020, Extraction, who is a significant shipper on our Grand Mesa pipeline, filed a petition for bankruptcy under Chapter 11 of Development Agreement

the bankruptcy code. Extraction had transportation contracts pursuant to which it had committed to ship crude oil on our pipeline through October 2026. As part of the bankruptcy filing, Extraction requested that the court authorize it to reject these transportation contracts, effective June 14, 2020, and on November 2, 2020, the bankruptcy court issued a bench ruling granting Extraction’s motion to reject the transportation contracts effective as of June 14, 2020. On June 3, 2016,December 21, 2020, we entered intoannounced a purchase and saleglobal settlement agreement with Extraction, as it relates to Extraction’s emergence from bankruptcy, which occurred on January 21, 2021. Among other consideration, the counterparty toglobal settlement agreement provides for the developmentfollowing: (i) a new long-term supply agreement, which includes a significant acreage dedication in the DJ Basin, and retains Extraction’s crude oil volumes for shipping on our Water Solutions segment. Total cash consideration paidGrand Mesa Pipeline; (ii) a new rate structure under the supply agreement was $49.6 million and in return we received the following:

Termination of the development agreement (see Note 7);
Additional interestwhich is based on calendar month average New York Mercantile Exchange (“NYMEX”) prices with an agreed upon differential plus an increase in the water pipeline company we acquired inrate when those NYMEX prices exceed $50.00 per barrel; and (iii) the receipt of $35.0 million from Extraction as a liquidated payment for our unsecured claims, which was received on January 2016;21, 2021.
Release of contingent consideration liabilities attributed to certain of our water treatment and disposal facilities;

F-58
F-47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Certain parcelsAs a result of landentering into the global settlement agreement, we determined that the customer commitment intangible asset related to one of the transportation contracts was impaired as of December 31, 2020 and permits to develop saltwaterrecorded an impairment charge of $145.8 million, which was calculated as the difference between the carrying value of the intangible asset of $180.8 million and the $35.0 million received from Extraction. We recorded the impairment charge within loss on disposal wells and other parcelsor impairment of land containing water wells and equipment; and
A two-year non-compete agreement with the counterparty.
assets, netWe accounted in our consolidated statement of operations for the transactionyear ended March 31, 2021. We also determined, as a result of these transactions, that it was more likely than not, that the fair value of our Crude Oil Logistics reporting unit was less than its carrying value and assessed goodwill for impairment, which resulted in an acquisitionimpairment charge of assets. We allocated $1.2$237.8 million. See Note 5 for a further discussion of the total considerationimpairment of goodwill.

Extraction continued to property, plantutilize, during the bankruptcy period, the services under the transportation contracts by nominating and equipment, $3.3delivering barrels to be shipped on our pipeline. As of September 30, 2020, Extraction owed us $5.7 million related to intangible assets, $2.8 million to noncontrolling interest, $25.5 million to the release of contingent consideration liabilities and $16.9 million to the termination of the development agreement. We recorded a $21.3 million gain on the release of $46.8 million of contingent consideration liabilities,deficiency volumes, which was recordedthe difference between the actual volumes shipped and the minimum volume commitment specified under the contracts. Following our global settlement, we deemed this amount uncollectible and wrote off the entire balance to bad debt expense within (loss) gain on early extinguishment of liabilities, net in our consolidated statement of operations during the year ended March 31, 2021.

Sale of Certain Assets

During the three months ended December 31, 2020, we sold certain permits, land and a saltwater disposal facility to WaterBridge Resources LLC for total proceeds of $43.2 million. We recorded a gain of $14.0 million within loss on disposal or impairment of assets, net in our consolidated statement of operations for the year ended March 31, 2021.

As part of the sale of our South Pecos water disposal business in February 2019, WaterBridge Resources LLC also had the option to acquire additional land and permits once the permitting process had been completed. During the year ended March 31, 2017. For the termination2020, WaterBridge Resources LLC acquired two additional permits and we received proceeds of the development agreement, we$15.0 million and recorded a lossgain of $22.7$14.5 million which included the carrying value of the development agreement asset that was written off (see Note 7). This loss was recorded within loss (gain) on disposal or impairment of assets, net in our consolidated statement of operations duringfor the year ended March 31, 2020.

Note 18—Discontinued Operations

As previously disclosed, on September 30, 2019, we completed the sale of 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:
Year Ended March 31,
20212020
(in thousands)
Revenues$16,198 $12,186,862 
Cost of sales16,556 12,193,307 
Operating expenses290 6,997 
General and administrative expense— 56 
Depreciation and amortization— 749 
Loss on disposal or impairment of assets, net (1)1,174 203,990 
Operating loss from discontinued operations(1,822)(218,237)
Interest expense— (111)
Other income, net— 133 
Loss from discontinued operations before taxes(1,822)(218,215)
Income tax benefit (expense)53 (20)
Loss from discontinued operations, net of tax$(1,769)$(218,235)
(1)    Amount for the year ended March 31, 2017.

Sale2021 includes a loss of TLP Common Units

On April 1, 2016, we sold all$1.0 million on the sale of Gas Blending and $0.2 million on the TLP common units we owned to ArcLightsale of TPSL. Amount for approximately $112.4 million in cash and recorded a gain on disposal of $104.1 million during the year ended March 31, 2017. This gain is reported within2020 includes a loss (gain)of $182.1 million on disposal or impairmentthe sale of assets, net in our consolidated statementTPSL, a loss of operations.

Note 17—Assets, Liabilities$6.3 million on the sale of Mid-Con, a loss of $14.5 million on the sale of Gas Blending and Redeemable Noncontrolling Interest Held for Sale and Discontinued Operations

As discussed in Note 1, asa loss of June 30, 2018, we met the criteria for classifying the assets, liabilities and redeemable noncontrolling interest of our Retail Propane segment as held for sale and the operations as discontinued. On March 30, 2018, we sold a portion of our Retail Propane segment to DCC for net proceeds of $212.4$1.0 million in cash, and recorded a gain on disposal of $89.3 million during the year ended March 31, 2018. On July 10, 2018, we completed the sale of virtually all of our remaining Retail Propane segment to Superior for net proceeds of $889.8 million in cash, and recorded a gainPlus Corp. on disposal of $408.9 million during the year ended March 31, 2019. On August 14, 2018, we sold our previously held interest in Victory Propane. See Note 1 for a further discussion.July 10, 2018.

The following table summarizes the major classes of assets, liabilities and redeemable noncontrolling interest classified as held for sale at March 31, 2018 (in thousands):
F-48
Assets Held for Sale  
Cash and cash equivalents $4,113
Accounts receivable-trade, net 45,924
Inventories 13,250
Prepaid expenses and other current assets 2,796
Property, plant and equipment, net 201,340
Goodwill 107,951
Intangible assets, net 141,328
Other assets 902
Total assets held for sale $517,604
   
Liabilities and Redeemable Noncontrolling Interest Held for Sale  
Accounts payable-trade $7,790
Accrued expenses and other payables 6,583
Advance payments received from customers 12,842
Current maturities of long-term debt 2,550
Long-term debt, net 2,888
Redeemable noncontrolling interest 9,927
Total liabilities and redeemable noncontrolling interest held for sale $42,580


F-59

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


The following table summarizes the results of operations from discontinued operations related to our former Retail Propane segment for the periods indicated:
  Year Ended March 31,
  2019 2018 2017
  (in thousands)
Revenues $70,859
 $521,511
 $413,206
Cost of sales 36,758
 269,367
 191,589
Operating expenses 27,729
 129,789
 118,922
General and administrative expense 2,589
 11,322
 10,761
Depreciation and amortization 8,706
 43,692
 42,966
Gain on disposal or impairment of assets, net (1) (407,608) (88,209) (287)
Operating income from discontinued operations 402,685
 155,550
 49,255
Equity in earnings (loss) of unconsolidated entities 1,183
 425
 (746)
Interest expense (125) (422) (484)
Other income, net 364
 1,330
 1,052
Income from discontinued operations before taxes (2) 404,107
 156,883
 49,077
Income tax expense (988) (103) (5)
Income from discontinued operations, net of tax $403,119
 $156,780
 $49,072
(1)Amount for the year ended March 31, 2019 includes a gain of $408.9 million on the sale of virtually all of our remaining Retail Propane segment to Superior on July 10, 2018, partially offset by a loss of $1.3 million on the sale of a portion of our Retail Propane segment to DCC on March 30, 2018 related to a working capital adjustment.
(2)Amounts include income (loss) attributable to redeemable noncontrolling interests. Loss attributable to redeemable noncontrolling interest was $0.4 million for the year ended March 31, 2019 and income attributable to redeemable noncontrolling interest was $1.0 million for the year ended March 31, 2018.

Continuing Involvement

As of March 31, 2019, we have commitments to sell up to 7.4 million gallons of propane, valued at $5.7 million (based on the contract price) to Superior and DCC, the purchasers of our former Retail Propane segment, through March 2020. During the year ended March 31, 2019, we received a combined $84.2 million from Superior and DCC for propane sold to them during the period.

Note 18—Quarterly Financial Data (Unaudited)

The following tables summarize our unaudited quarterly financial data. The computation of net income (loss) per common unit is done separately by quarter and year. The total of net income (loss) per common unit of the individual quarters may not equal net income (loss) per common unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

19—Subsequent Events
Our former Retail Propane segment’s business (included within discontinued operations, see Note 17) is seasonal due to weather conditions in our service areas. Its results are affected by winter heating season requirements, which generally results in net income during the period from October through March of each year and either net losses or lower net income during the period from April through September of each year. Our Liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year, and year to year.

F-60

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


 Quarter Ended Year Ended
 June 30, 2018 September 30, 2018 December 31, 2018 March 31, 2019 March 31, 2019
 (in thousands, except unit and per unit amounts)
Total revenues$5,844,434
 $6,654,634
 $6,376,820
 $5,141,019
 $24,016,907
Total cost of sales$5,696,156
 $6,509,527
 $6,114,384
 $4,964,850
 $23,284,917
(Loss) income from continuing operations$(165,248) $(53,508) $110,432
 $44,600
 $(63,724)
Net (loss) income$(169,289) $354,939
 $110,528
 $43,217
 $339,395
Net (loss) income attributable to NGL Energy Partners LP$(168,546) $355,505
 $110,835
 $62,253
 $360,047
Basic (loss) income per common unit         
(Loss) income from continuing operations$(1.52) $(0.63) $0.65
 $0.21
 $(1.26)
Net (loss) income$(1.55) $2.70
 $0.65
 $0.20
 $2.01
Diluted (loss) income per common unit         
(Loss) income from continuing operations$(1.52) $(0.63) $0.64
 $0.20
 $(1.26)
Net (loss) income$(1.55) $2.70
 $0.64
 $0.19
 $2.01
Basic weighted average common units outstanding121,544,421
 122,380,197
 123,892,680
 124,262,014
 123,017,064
Diluted weighted average common units outstanding121,544,421
 122,380,197
 125,959,751
 126,926,589
 123,017,064
          
 Quarter Ended Year Ended
 June 30, 2017 September 30, 2017 December 31, 2017 March 31, 2018 March 31, 2018
 (in thousands, except unit and per unit amounts)
Total revenues$3,730,705
 $3,876,676
 $4,353,783
 $4,946,132
 $16,907,296
Total cost of sales$3,628,683
 $3,757,450
 $4,235,867
 $4,790,641
 $16,412,641
(Loss) income from continuing operations$(58,049) $(164,293) $31,827
 $(35,870) $(226,385)
Net (loss) income$(63,707) $(173,579) $56,769
 $110,912
 $(69,605)
Net (loss) income attributable to NGL Energy Partners LP$(63,362) $(173,371) $56,256
 $109,602
 $(70,875)
Basic (loss) income per common unit         
(Loss) income from continuing operations$(0.56) $(1.49) $0.13
 $(0.44) $(2.37)
Net (loss) income$(0.61) $(1.56) $0.33
 $0.76
 $(1.08)
Diluted (loss) income per common unit         
(Loss) income from continuing operations$(0.56) $(1.49) $0.12
 $(0.28) $(2.37)
Net (loss) income$(0.61) $(1.56) $0.32
 $0.71
 $(1.08)
Basic weighted average common units outstanding120,535,909
 121,314,636
 120,844,008
 121,271,959
 120,991,340
Diluted weighted average common units outstanding120,535,909
 121,314,636
 124,161,966
 146,868,349
 120,991,340


The following summarizes significant items recognized during the years ended March 31, 2019 and 2018:

Year Ended March 31, 2019

During the fourth quarter of fiscal year 2019, we recorded a goodwill impairment charge related to Sawtooth (see Note 6);
On February 28, 2019, we sold our South Pecos water disposal business and recorded a gain (see Note 16);
On November 30, 2018, we sold our Bakken saltwater disposal business and recorded a gain (see Note 16);
On July 10, 2018, we sold virtually all of our remaining Retail Propane segment and recorded a gain (see Note 17);
On May 3, 2018, we sold our previously held interest in E Energy Adams, LLC and recorded a gain (see Note 2); and
During fiscal year 2019, we repurchased a portion of our 2019 Notes and 2023 Notes and redeemed the outstanding 2019 Notes and 2021 Notes and recorded a loss on the early extinguishment of these notes (see Note 8).


F-61

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


Year Ended March 31, 2018

On March 30, 2018, we sold a portion of our Retail Propane segment to DCC and recorded a gain (see Note 17);
On March 30, 2018, we closed the joint venture related to Sawtooth and sold a portion of our interest in Sawtooth (see Note 16);
On December 22, 2017, we sold our previously held interest in Glass Mountain (see Note 16);
During the second quarter of fiscal year 2018, we recorded a goodwill impairment charge related to Sawtooth (see Note 6);
During fiscal year 2018, we repurchased a portion of our 2019 Notes, 2023 Notes and 2025 Notes and recorded a net gain on the early extinguishment of these notes (see Note 8); and
During the first and third quarters of fiscal year 2018, we repurchased a portion of and then all of the remaining outstanding Senior Secured Notes and recorded a loss on the early extinguishment of these notes (see Note 8).

Note 19—Subsequent Events

Issuance of Class C Preferred Units

On April 2, 2019, we issued the Class C Preferred Units. See Note 10 for a further discussion.

Redemption of Class A Preferred Units

On April 5, 2019, we made a partial redemption of the Class A Preferred Units and on May 11, 2019, we redeemed the remaining outstanding Class A Preferred Units. See Note 10 for a further discussion. In connection with the redemption, Jared Parker resigned from the board of directors of our general partner.

Exercise of Warrants

On April 5, 2019, Oaktree exercised all of its remaining warrants to purchase common units. See Note 10 for a further discussion.

Issuance of 2026 Notes

On April 9, 2019, we issued the 2026 Notes. See Note 8 for a further discussion.

Acquisitions

On May 14, 2019, we entered into a definitive agreement with Mesquite Disposals Unlimited, LLC (“Mesquite”) to acquire all of its assets for approximately $892.5 million. Mesquite SWD Inc. will remain the operator of the Mesquite assets led by Mesquite’s current management team. The assets consist of a fully interconnected produced water pipeline transportation and disposal system in Eddy and Lea Counties, New Mexico, and Loving County, Texas. At closing, the Mesquite system is expected to have 35 saltwater disposal wells in total. The transaction is subject to certain regulatory and other customary closing conditions and is expected to close in July 2019.

On April 10, 2019,13, 2022, we acquired one saltwater disposal facility (including three saltwater disposal wells)amended the ABL Facility to increase the commitments to $600.0 million under the accordion feature within the ABL Facility. As part of the amendment, we agreed to reduce the commitments back to $500.0 million on or before March 31, 2023. In addition, the sub-limit for total considerationletters of approximately $53.0 million.

On April 3, 2019, we acquired land and two saltwater disposal wells for total consideration of approximately $13.0 million.


F-62

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notescredit was increased to Consolidated Financial Statements (Continued)


Note 20—Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the Senior Unsecured Notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the consolidating financial information for NGL Energy Partners LP (Parent), NGL Energy Finance Corp., the guarantor subsidiaries on a combined basis,$250.0 million, and the non-guarantor subsidiaries on a combined basis inLIBOR benchmark was replaced with the tables below. NGL Energy Partners LP and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes. Since NGL Energy Partners LP received the proceeds from the issuance of the Senior Unsecured Notes, all activity has been reflected in the NGL Energy Partners LP (Parent) column in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the Senior Unsecured Notes. For purposes of the tables below, when the status of a subsidiary changes, all subsidiary activity is included in either the guarantor subsidiaries column or non-guarantor subsidiaries column based on the status of the subsidiary at the balance sheet date regardless of activity during the year.

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

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

As discussed further in Note 1 and Note 17, the assets and liabilities related to our former Retail Propane segment have been classified as held for sale within our March 31, 2018 consolidated balance sheet and the results of operations and cash flows related to our former Retail Propane segment (including equity in earnings of Victory Propane) have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted in the consolidated statements of operations and consolidated statements of cash flows.

daily simple SOFR benchmark.
F-63
F-49

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Balance Sheet
(in Thousands)
  March 31, 2019
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
ASSETS            
CURRENT ASSETS:            
Cash and cash equivalents $12,798
 $
 $3,728
 $2,046
 $
 $18,572
Accounts receivable-trade, net of allowance for doubtful accounts 
 
 1,160,908
 2,011
 
 1,162,919
Accounts receivable-affiliates 
 
 12,867
 
 
 12,867
Inventories 
 
 462,109
 1,034
 
 463,143
Prepaid expenses and other current assets 
 
 154,697
 475
 
 155,172
Total current assets 12,798
 
 1,794,309
 5,566
 
 1,812,673
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation 
 
 1,635,637
 208,856
 
 1,844,493
GOODWILL 
 
 1,140,686
 5,175
 
 1,145,861
INTANGIBLE ASSETS, net of accumulated amortization 
 
 862,988
 75,347
 
 938,335
INVESTMENTS IN UNCONSOLIDATED ENTITIES 
 
 1,127
 
 
 1,127
NET INTERCOMPANY RECEIVABLES (PAYABLES) 862,186
 
 (808,610) (53,576) 
 
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES 2,503,848
 
 170,690
 
 (2,674,538) 
OTHER NONCURRENT ASSETS 
 
 160,004
 
 
 160,004
Total assets $3,378,832
 $
 $4,956,831
 $241,368
 $(2,674,538) $5,902,493
LIABILITIES AND EQUITY            
CURRENT LIABILITIES AND REDEEMABLE NONCONTROLLING INTEREST:            
Accounts payable-trade $
 $
 $957,724
 $6,941
 $
 $964,665
Accounts payable-affiliates 1
 
 28,468
 
 
 28,469
Accrued expenses and other payables 25,497
 
 221,456
 1,497
 
 248,450
Advance payments received from customers 
 
 8,010
 911
 
 8,921
Current maturities of long-term debt 
 
 648
 
 
 648
Total current liabilities and redeemable noncontrolling interest 25,498
 
 1,216,306
 9,349
 
 1,251,153
LONG-TERM DEBT, net of debt issuance costs and current maturities 984,450
 
 1,175,683
 
 
 2,160,133
OTHER NONCURRENT LIABILITIES 
 
 60,994
 2,581
 
 63,575
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS 149,814
 
 
 
 
 149,814
EQUITY:            
Partners’ equity 2,219,070
 
 2,503,848
 229,693
 (2,733,286) 2,219,325
Accumulated other comprehensive loss 
 
 
 (255) 
 (255)
Noncontrolling interests 
 
 
 
 58,748
 58,748
Total equity 2,219,070
 
 2,503,848
 229,438
 (2,674,538) 2,277,818
Total liabilities and equity $3,378,832
 $
 $4,956,831
 $241,368
 $(2,674,538) $5,902,493


F-64

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Balance Sheet
(in Thousands)
  March 31, 2018
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
ASSETS            
CURRENT ASSETS:            
Cash and cash equivalents $16,915
 $
 $3,329
 $1,850
 $
 $22,094
Accounts receivable-trade, net of allowance for doubtful accounts 
 
 1,021,616
 5,148
 
 1,026,764
Accounts receivable-affiliates 
 
 4,772
 
 
 4,772
Inventories 
 
 550,978
 325
 
 551,303
Prepaid expenses and other current assets 
 
 128,311
 431
 
 128,742
Assets held for sale 
 
 490,800
 26,804
 
 517,604
Total current assets 16,915
 
 2,199,806
 34,558
 
 2,251,279
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation 
 
 1,371,495
 147,112
 
 1,518,607
GOODWILL 
 
 1,127,347
 77,260
 
 1,204,607
INTANGIBLE ASSETS, net of accumulated amortization 
 
 829,449
 83,705
 
 913,154
INVESTMENTS IN UNCONSOLIDATED ENTITIES 
 
 17,236
 
 
 17,236
NET INTERCOMPANY RECEIVABLES (PAYABLES) 2,110,940
 
 (2,121,741) 10,801
 
 
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES 1,703,327
 
 244,109
 
 (1,947,436) 
LOAN RECEIVABLE-AFFILIATE 
 
 1,200
 
 
 1,200
OTHER NONCURRENT ASSETS 
 
 245,039
 
 
 245,039
Total assets $3,831,182
 $
 $3,913,940
 $353,436
 $(1,947,436) $6,151,122
LIABILITIES AND EQUITY            
CURRENT LIABILITIES AND REDEEMABLE NONCONTROLLING INTEREST:            
Accounts payable-trade $
 $
 $850,607
 $2,232
 $
 $852,839
Accounts payable-affiliates 1
 
 1,253
 
 
 1,254
Accrued expenses and other payables 41,104
 
 181,115
 1,285
 
 223,504
Advance payments received from customers 
 
 4,507
 3,867
 
 8,374
Current maturities of long-term debt 
 
 646
 
 
 646
Liabilities and redeemable noncontrolling interest held for sale 
 
 30,066
 12,514
 
 42,580
Total current liabilities and redeemable noncontrolling interest 41,105
 
 1,068,194
 19,898
 
 1,129,197
LONG-TERM DEBT, net of debt issuance costs and current maturities 1,704,909
 
 974,831
 
 
 2,679,740
OTHER NONCURRENT LIABILITIES 
 
 167,588
 5,926
 
 173,514
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS 82,576
 
 
 
 
 82,576
EQUITY:            
Partners’ equity 2,002,592
 
 1,704,896
 327,858
 (2,030,939) 2,004,407
Accumulated other comprehensive loss 
 
 (1,569) (246) 
 (1,815)
Noncontrolling interests 
 
 
 
 83,503
 83,503
Total equity 2,002,592
 
 1,703,327
 327,612
 (1,947,436) 2,086,095
Total liabilities and equity $3,831,182
 $
 $3,913,940
 $353,436
 $(1,947,436) $6,151,122


F-65

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Operations
(in Thousands)
  Year Ended March 31, 2019
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
REVENUES $
 $
 $23,993,347
 $27,542
 $(3,982) $24,016,907
COST OF SALES 
 
 23,287,875
 1,024
 (3,982) 23,284,917
OPERATING COSTS AND EXPENSES:            
Operating 
 
 227,216
 13,468
 
 240,684
General and administrative 
 
 106,722
 812
 
 107,534
Depreciation and amortization 
 
 202,400
 10,460
 
 212,860
(Gain) loss on disposal or impairment of assets, net 
 
 (31,924) 66,220
 
 34,296
Revaluation of liabilities 
 
 (5,373) 
 
 (5,373)
Operating Income (Loss) 
 
 206,431
 (64,442) 
 141,989
OTHER INCOME (EXPENSE):            
Equity in earnings of unconsolidated entities 
 
 2,533
 
 
 2,533
Interest expense (104,716) 
 (60,009) (46) 45
 (164,726)
Loss on early extinguishment of liabilities, net (12,340) 
 
 
 
 (12,340)
Other expense, net 
 
 (29,715) 
 (231) (29,946)
(Loss) Income From Continuing Operations Before Income Taxes (117,056) 
 119,240
 (64,488) (186) (62,490)
INCOME TAX EXPENSE 
 
 (1,234) 
 
 (1,234)
EQUITY IN NET INCOME (LOSS) FROM CONTINUING OPERATIONS OF CONSOLIDATED SUBSIDIARIES 477,103
 
 (44,865) 
 (432,238) 
Income (Loss) From Continuing Operations 360,047
 
 73,141
 (64,488) (432,424) (63,724)
Income (Loss) From Discontinued Operations, Net of Tax 
 
 403,962
 (1,029) 186
 403,119
Net Income (Loss) 360,047
 
 477,103
 (65,517) (432,238) 339,395
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS         20,206
 20,206
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS         446
 446
NET INCOME (LOSS) ATTRIBUTABLE TO NGL ENERGY PARTNER LP $360,047
 $
 $477,103
 $(65,517) $(411,586) $360,047


F-66

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Operations
(in Thousands)
  Year Ended March 31, 2018
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
REVENUES $
 $
 $16,888,834
 $19,954
 $(1,492) $16,907,296
COST OF SALES 
 
 16,412,642
 1,491
 (1,492) 16,412,641
OPERATING COSTS AND EXPENSES:            
Operating 
 
 194,048
 7,020
 
 201,068
General and administrative 
 
 97,552
 577
 
 98,129
Depreciation and amortization 
 
 198,119
 10,901
 
 209,020
(Gain) loss on disposal or impairment of assets, net 
 
 (133,979) 116,875
 
 (17,104)
Revaluation of liabilities 
 
 20,124
 592
 
 20,716
Operating Income (Loss) 
 
 100,328
 (117,502) 
 (17,174)
OTHER INCOME (EXPENSE):            
Equity in earnings of unconsolidated entities 
 
 7,539
 
 
 7,539
Interest expense (142,159) 
 (56,988) (46) 45
 (199,148)
Loss on early extinguishment of liabilities, net (23,201) 
 
 
 
 (23,201)
Other income, net 
 
 7,753
 19
 (819) 6,953
(Loss) Income From Continuing Operations Before Income Taxes (165,360) 
 58,632
 (117,529) (774) (225,031)
INCOME TAX EXPENSE 
 
 (1,354) 
 
 (1,354)
EQUITY IN NET INCOME (LOSS) FROM CONTINUING OPERATIONS OF CONSOLIDATED SUBSIDIARIES 94,485
 
 (116,224) 
 21,739
 
Loss From Continuing Operations (70,875) 
 (58,946) (117,529) 20,965
 (226,385)
Income From Discontinued Operations, Net of Tax 
 
 153,431
 2,575
 774
 156,780
Net (Loss) Income (70,875) 
 94,485
 (114,954) 21,739
 (69,605)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS         (240) (240)
LESS: NET INCOME ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS         (1,030) (1,030)
NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNER LP $(70,875) $
 $94,485
 $(114,954) $20,469
 $(70,875)


F-67

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Operations
(in Thousands)
  Year Ended March 31, 2017
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
REVENUES $
 $
 $12,688,354
 $19,639
 $(790) $12,707,203
COST OF SALES 
 
 12,228,661
 533
 (790) 12,228,404
OPERATING COSTS AND EXPENSES:            
Operating 
 
 182,476
 6,527
 
 189,003
General and administrative 
 
 105,402
 403
 
 105,805
Depreciation and amortization 
 
 172,798
 7,441
 
 180,239
Gain on disposal or impairment of assets, net 
 
 (208,890) 
 
 (208,890)
Revaluation of liabilities 
 
 6,305
 412
 
 6,717
Operating Income 
 
 201,602
 4,323
 
 205,925
OTHER INCOME (EXPENSE):            
Equity in earnings of unconsolidated entities 
 
 3,830
 
 
 3,830
Revaluation of investments 
 
 (14,365) 
 
 (14,365)
Interest expense (91,259) 
 (58,607) (174) 46
 (149,994)
Gain on early extinguishment of liabilities, net 8,507
 
 16,220
 
 
 24,727
Other income, net 
 
 27,205
 
 (593) 26,612
(Loss) Income From Continuing Operations Before Income Taxes (82,752) 
 175,885
 4,149
 (547) 96,735
INCOME TAX EXPENSE 
 
 (1,933) 
 
 (1,933)
EQUITY IN NET INCOME (LOSS) FROM CONTINUING OPERATIONS OF CONSOLIDATED SUBSIDIARIES 219,794
 
 (1,336) 
 (218,458) 
Income From Continuing Operations 137,042
 
 172,616
 4,149
 (219,005) 94,802
Income From Discontinued Operations, Net of Tax 
 
 47,178
 1,347
 547
 49,072
Net Income 137,042
 
 219,794
 5,496
 (218,458) 143,874
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS         (6,832) (6,832)
NET INCOME ATTRIBUTABLE TO NGL ENERGY PARTNER LP $137,042
 $
 $219,794
 $5,496
 $(225,290) $137,042


F-68

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statements of Comprehensive Income (Loss)
(in Thousands)
  Year Ended March 31, 2019
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
Net income (loss) $360,047
 $
 $477,103
 $(65,517) $(432,238) $339,395
Other comprehensive (loss) income 
 
 (18) 9
 
 (9)
Comprehensive income (loss) $360,047
 $
 $477,085
 $(65,508) $(432,238) $339,386

  Year Ended March 31, 2018
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
Net (loss) income $(70,875) $
 $94,485
 $(114,954) $21,739
 $(69,605)
Other comprehensive income (loss) 
 
 58
 (45) 
 13
Comprehensive (loss) income $(70,875) $
 $94,543
 $(114,999) $21,739
 $(69,592)

  Year Ended March 31, 2017
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating
Adjustments
 Consolidated
             
Net income $137,042
 $
 $219,794
 $5,496
 $(218,458) $143,874
Other comprehensive loss 
 
 (1,626) (45) 
 (1,671)
Comprehensive income $137,042
 $
 $218,168
 $5,451
 $(218,458) $142,203


F-69

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Cash Flows
(in Thousands)
  Year Ended March 31, 2019
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating Adjustments Consolidated
OPERATING ACTIVITIES:            
Net cash (used in) provided by operating activities-continuing operations $(116,033) $
 $451,284
 $(27,551) $(186) $307,514
Net cash provided by operating activities-discontinued operations 
 
 26,515
 3,221
 
 29,736
Net cash (used in) provided by operating activities (116,033) 
 477,799
 (24,330) (186) 337,250
INVESTING ACTIVITIES:            
Capital expenditures 
 
 (414,549) (41,064) 
 (455,613)
Acquisitions, net of cash acquired 
 
 (313,009) (3,927) 
 (316,936)
Net settlements of commodity derivatives 
 
 18,405
 
 
 18,405
Proceeds from sales of assets 
 
 16,177
 
 
 16,177
Proceeds from divestitures of businesses and investments, net 
 
 335,809
 
 
 335,809
Investments in unconsolidated entities 
 
 (389) 
 
 (389)
Distributions of capital from unconsolidated entities 
 
 1,440
 
 
 1,440
Repayments on loan for natural gas liquids facility 
 
 10,336
 
 
 10,336
Loan to affiliate 
 
 (1,515) 
 
 (1,515)
Net cash used in investing activities-continuing operations 
 
 (347,295) (44,991) 
 (392,286)
Net cash provided by investing activities-discontinued operations 
 
 838,777
 6,982
 
 845,759
Net cash provided by (used in) investing activities 
 
 491,482
 (38,009) 
 453,473
FINANCING ACTIVITIES:            
Proceeds from borrowings under revolving credit facilities 
 
 4,098,500
 
 
 4,098,500
Payments on revolving credit facilities 
 
 (3,897,000) 
 
 (3,897,000)
Repayment and repurchase of senior secured and senior unsecured notes (737,058) 
 
 
 
 (737,058)
Payments on other long-term debt 
 
 (653) 
 
 (653)
Debt issuance costs (30) 
 (1,353) 
 
 (1,383)
Contributions from noncontrolling interest owners, net 
 
 
 169
 
 169
Distributions to general and common unit partners and preferred unitholders (236,633) 
 
 
 
 (236,633)
Repurchase of warrants (14,988) 
 
 
 
 (14,988)
Common unit repurchases and cancellations (297) 
 
 
 
 (297)
Payments for settlement and early extinguishment of liabilities 
 
 (4,577) 
 
 (4,577)
Net changes in advances with consolidated entities 1,100,922
 
 (1,163,504) 62,396
 186
 
Net cash provided by (used in) financing activities-continuing operations 111,916
 
 (968,587) 62,565
 186
 (793,920)
Net cash used in financing activities-discontinued operations 
 
 (295) (30) 
 (325)
Net cash provided by (used in) financing activities 111,916
 
 (968,882) 62,535
 186
 (794,245)
Net (decrease) increase in cash and cash equivalents (4,117) 
 399
 196
 
 (3,522)
Cash and cash equivalents, beginning of period 16,915
 
 3,329
 1,850
 
 22,094
Cash and cash equivalents, end of period $12,798
 $
 $3,728
 $2,046
 $
 $18,572


F-70

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Cash Flows
(in Thousands)
  Year Ended March 31, 2018
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating Adjustments Consolidated
OPERATING ACTIVITIES:            
Net cash (used in) provided by operating activities-continuing operations $(141,967) $
 $186,959
 $9,411
 $(774) $53,629
Net cash provided by operating activities-discontinued operations 
 
 80,857
 3,481
 
 84,338
Net cash (used in) provided by operating activities (141,967) 
 267,816
 12,892
 (774) 137,967
INVESTING ACTIVITIES:            
Capital expenditures 
 
 (130,760) (3,001) 
 (133,761)
Acquisitions, net of cash acquired 
 
 3,100
 (22,997) 
 (19,897)
Net settlements of commodity derivatives 
 
 (100,405) 
 
 (100,405)
Proceeds from sales of assets 
 
 33,844
 
 
 33,844
Proceeds from divestitures of businesses and investments, net 
 
 292,112
 37,668
 
 329,780
Transaction with Victory Propane (Note 13) 
 
 (6,424) 
 
 (6,424)
Investments in unconsolidated entities 
 
 (21,465) 
 
 (21,465)
Distributions of capital from unconsolidated entities 
 
 11,969
 
 
 11,969
Repayments on loan for natural gas liquids facility 
 
 10,052
 
 
 10,052
Loan to affiliate 
 
 (2,510) 
 
 (2,510)
Repayments on loan to affiliate 
 
 4,160
 
 
 4,160
Net cash provided by investing activities-continuing operations 
 
 93,673
 11,670
 
 105,343
Net cash provided by (used in) investing activities-discontinued operations 
 
 165,958
 (719) 
 165,239
Net cash provided by investing activities 
 
 259,631
 10,951
 
 270,582
FINANCING ACTIVITIES:            
Proceeds from borrowings under revolving credit facilities 
 
 2,434,500
 
 
 2,434,500
Payments on revolving credit facilities 
 
 (2,279,500) 
 
 (2,279,500)
Repayment and repurchase of senior secured and senior unsecured notes (486,699) 
 
 
 
 (486,699)
Payments on other long-term debt 
 
 (877) 
 
 (877)
Debt issuance costs (692) 
 (2,008) 
 
 (2,700)
Contributions from noncontrolling interest owners, net 
 
 
 23
 
 23
Distributions to general and common unit partners and preferred unitholders (225,067) 
 
 
 
 (225,067)
Distributions to noncontrolling interest owners 
 
 
 (3,082) 
 (3,082)
Proceeds from sale of preferred units, net of offering costs 202,731
 
 
 
 
 202,731
Repurchase of warrants (10,549) 
 
 
 
 (10,549)
Common unit repurchases and cancellations (15,817) 
 
 
 
 (15,817)
Payments for settlement and early extinguishment of liabilities 
 
 (3,408) 
 
 (3,408)
Net changes in advances with consolidated entities 688,718
 
 (669,452) (20,040) 774
 
Net cash provided by (used in) financing activities-continuing operations 152,625
 
 (520,745) (23,099) 774
 (390,445)
Net cash used in financing activities-discontinued operations 
 
 (3,446) (390) 
 (3,836)
Net cash provided by (used in) financing activities 152,625
 
 (524,191) (23,489) 774
 (394,281)
Net increase in cash and cash equivalents 10,658
 
 3,256
 354
 
 14,268
Cash and cash equivalents, beginning of period 6,257
 
 73
 1,496
 
 7,826
Cash and cash equivalents, end of period $16,915
 $
 $3,329
 $1,850
 $
 $22,094


F-71

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)



Consolidating Statement of Cash Flows
(in Thousands)
  Year Ended March 31, 2017
  NGL Energy
Partners LP
(Parent)
 NGL Energy
Finance Corp.
 Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Consolidating Adjustments Consolidated
OPERATING ACTIVITIES:            
Net cash (used in) provided by operating activities-continuing operations $(749,250) $
 $635,322
 $16,675
 $(547) $(97,800)
Net cash provided by operating activities-discontinued operations 
 
 67,733
 5,029
 
 72,762
Net cash (used in) provided by operating activities (749,250) 
 703,055
 21,704
 (547) (25,038)
INVESTING ACTIVITIES:            
Capital expenditures 
 
 (338,569) (6,367) 
 (344,936)
Acquisitions, net of cash acquired 
 
 (41,928) 
 
 (41,928)
Net settlements of commodity derivatives 
 
 (37,086) 
 
 (37,086)
Proceeds from sales of assets 
 
 28,232
 
 
 28,232
Proceeds from divestitures of businesses and investments, net 
 
 112,370
 22,000
 
 134,370
Investments in unconsolidated entities 
 
 (2,105) 
 
 (2,105)
Distributions of capital from unconsolidated entities 
 
 9,692
 
 
 9,692
Repayments on loan for natural gas liquids facility 
 
 8,916
 
 
 8,916
Loan to affiliate 
 
 (3,200) 
 
 (3,200)
Repayments on loan to affiliate 
 
 655
 
 
 655
Payment to terminate development agreement 
 
 (16,875) 
 
 (16,875)
Net cash (used in) provided by investing activities-continuing operations 
 
 (279,898) 15,633
 
 (264,265)
Net cash used in investing activities-discontinued operations 
 
 (86,463) (12,398) 
 (98,861)
Net cash (used in) provided by investing activities 
 
 (366,361) 3,235
 
 (363,126)
FINANCING ACTIVITIES:            
Proceeds from borrowings under revolving credit facilities 
 
 1,700,000
 
 
 1,700,000
Payments on revolving credit facilities 
 
 (2,733,500) 
 
 (2,733,500)
Issuance of senior unsecured notes 1,200,000
 
 
 
 
 1,200,000
Repayment and repurchase of senior secured and senior unsecured notes (21,193) 
 
 
 
 (21,193)
Payments on other long-term debt 
 
 (46,153) 
 
 (46,153)
Debt issuance costs (21,868) 
 (11,690) 
 
 (33,558)
Contributions from general partner 49
 
 
 
 
 49
Contributions from noncontrolling interest owners, net 
 
 
 672
 
 672
Distributions to general and common unit partners and preferred unitholders (181,581) 
 
 
 
 (181,581)
Distributions to noncontrolling interest owners 
 
 
 (3,292) 
 (3,292)
Proceeds from sale of preferred units, net of offering costs 234,975
 
 
 
 
 234,975
Proceeds from sale of common units, net of offering costs 287,136
 
 
 
 
 287,136
Payments for settlement and early extinguishment of liabilities 
 
 (28,468) 
 
 (28,468)
Net changes in advances with consolidated entities (767,760) 
 788,334
 (21,121) 547
 
Net cash provided by (used in) financing activities-continuing operations 729,758
 
 (331,477) (23,741) 547
 375,087
Net cash used in financing activities-discontinued operations 
 
 (3,443) (190) 
 (3,633)
Net cash provided by (used in) financing activities 729,758
 
 (334,920) (23,931) 547
 371,454
Net (decrease) increase in cash and cash equivalents (19,492) 
 1,774
 1,008
 
 (16,710)
Cash and cash equivalents, beginning of period 25,749
 
 (1,701) 488
 
 24,536
Cash and cash equivalents, end of period $6,257
 $
 $73
 $1,496
 $
 $7,826



F-72