NGL Energy Partners LP 10-K

ngl-20220331 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (Mark One) ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended March 31, 2022 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission File Number: 001-35172 NGL Energy Partners LP (Exact Name of Registrant as Specified in Its Charter) Delaware 27-3427920 (State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 6120 South Yale Avenue, Suite 805 Tulsa, Oklahoma 74136 (Address of Principal Executive Offices) (Zip Code) ( 918) 481-1119 (Registrant’s Telephone Number, Including Area Code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Trading Symbols Name of Each Exchange on Which Registered Common units representing Limited Partner Interests NGL New York Stock Exchange Fixed-to-floating rate cumulative redeemable perpetual preferred units NGL-PB New York Stock Exchange Fixed-to-floating rate cumulative redeemable perpetual preferred units NGL-PC New York Stock Exchange 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 ☒ No ☐ 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 ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer o Accelerated filer x Non-accelerated filer o Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant 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 Act). Yes ☐ No ☒ The aggregate market value at September 30, 2021 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 ($ 2.37 per Common Unit) was $ 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 June 1, 2022, there were 130,695,970 common units issued and outstanding. TABLE OF CONTENTS PART I Item 1. Business 3 Item 1A. Risk Factors 22 Item 1B. Unresolved Staff Comments 49 Item 2. Properties 49 Item 3. Legal Proceedings 49 Item 4. Mine Safety Disclosures 49 PART II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities 50 Item 6. [Reserved] 51 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 51 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 87 Item 8. Financial Statements and Supplementary Data 90 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 90 Item 9A. Controls and Procedures 90 Item 9B. Other Information 92 Item 9 C . Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 92 PART III Item 10. Directors, Executive Officers and Corporate Governance 92 Item 11. Executive Compensation 97 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters 106 Item 13. Certain Relationships and Related Transactions, and Director Independence 108 Item 14. Principal Accountant Fees and Services 111 PART IV Item 15. Exhibit and Financial Statement Schedules 112 Item 16. Form 10-K Summary 116 i 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, biodiesel and energy prices generally; • the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, diesel and biodiesel; • the level of crude oil and natural gas drilling and production in areas where we have operations and facilities; • the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas; • the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel, and biodiesel; • the effect of natural disasters, earthquakes, hurricanes, tornados, lightning strikes, or other significant weather events; • the availability of local, intrastate, and interstate transportation infrastructure with respect to our transportation services; • the availability, price, and marketing of competing fuels; • the effect of energy conservation efforts on product demand; • energy efficiencies and technological trends; • issuance of executive orders, changes in applicable laws, regulations and policies, including tax, environmental, transportation, and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the effect of such laws, regulations and policies (now existing or in the future) on our business operations; • the effect of executive orders and legislative and regulatory actions on hydraulic fracturing, water disposal and transportation, and the treatment of flowback and produced water; • hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance; • the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other markets; • loss of key personnel; • the ability to renew contracts with key customers; • the ability to maintain or increase the margins we realize for our services; • the ability to renew leases for our leased equipment and storage facilities; • the nonpayment, nonperformance or bankruptcy by our counterparties; • the availability and cost of capital and our ability to access certain capital sources; • a deterioration of the credit and capital markets; • 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; 1 • changes in general economic conditions, including market and macroeconomic disruptions resulting from pandemics, including the current 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 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.” 2 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 45 individuals and entities that own all of the outstanding membership interests in our general partner. We have presented operational data in Part I, Item 1–“Business” for the year ended March 31, 2022. Unless otherwise indicated, this data is as of March 31, 2022. Item 1. Business Overview We are a diversified 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, we are a Delaware master limited partnership and our 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 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, 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 past 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 businesses in the Permian and Bakken 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 (“Gas Blending”) during the year ended March 31, 2020; and • Our interest in Sawtooth Caverns, LLC (“Sawtooth”) during the year ended March 31, 2022. 3 In our Water 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 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 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 believe are the core areas of our business and improved our overall financial position. These transactions are expected to position us for sustained growth in the future. For more information regarding our results of operations and reportable segments, see Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 11 to our consolidated financial statements included in this Annual Report. For more information regarding our 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 our Annual 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 7 to our consolidated financial statements included in this Annual Report. 4 Primary Service Areas The following map shows the primary service areas of our businesses at March 31, 2022: 5 Organizational Chart The following chart provides a summarized overview of our legal entity structure at March 31, 2022: (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. 6 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: • 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 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 7 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 8 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 of Number of Permitted Processing Capacity (barrels per day) Location Facilities Wells Own (1) Lease (2) Total Permian Basin Delaware Basin (3) - Texas and New Mexico 58 122 1,514,000 3,297,300 4,811,300 Midland Basin (3) - Texas 14 14 358,300 — 358,300 Eagle Ford Basin (3)(4) - Texas 22 36 549,000 362,000 911,000 DJ Basin - Colorado 13 32 393,000 162,500 555,500 Granite Wash (3) - Texas 2 3 60,000 — 60,000 Pinedale Anticline Basin (5) - Wyoming 1 4 — 90,240 90,240 Eaglebine - Texas 1 1 20,000 — 20,000 Total - All Facilities 111 212 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 9 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 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 operations are concentrated in and around four prolific crude oil producing regions in the United States - the DJ Basin in Colorado, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas and the United States Gulf Coast. Our 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. Grand Mesa commenced operations on November 1, 2016 and has operated continuously since then. The main line portion of this pipeline is comprised of an undivided interest with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) in which we have the right to use 150,000 barrels per day of capacity of the pipeline. During the year ended March 31, 2022, approximately 28.4 million barrels (volume amounts are from both internal and external parties) of crude oil were 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 and 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 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 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 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 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. 10 We currently transport crude oil using the following assets: • The Grand Mesa Pipeline, which is described above, and 20 other common carrier pipelines owned by third parties; • 396 owned and 210 leased railcars (all of which are leased or subleased to third parties); and • 13 owned towboats and 24 owned barges operating primarily in the intercoastal waterways of the United States Gulf Coast and along the Mississippi and Arkansas River systems. We purchased an additional barge in April 2022. All of our 396 owned railcars and 210 leased railcars are compliant with the standards for railcars built subsequent to 2011 for the commodities they are transporting. (See Part I, Item 1 “Government Regulation”). We also own 27 strategically located pipeline injection stations, the locations of which are summarized below. State Number of Pipeline Injection Stations Texas 13 New Mexico 6 Oklahoma 5 Kansas 3 Total 27 Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2022, 90% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment, of which CITGO Petroleum Corporation accounted for 12.8% of our consolidated revenues for the year ended March 31, 2022. Sales to this customer occur mainly out of our crude oil terminal in Cushing, Oklahoma. Additionally, certain key customers of the Crude Oil Logistics segment contribute significantly to the cash flows and profitability of the organization. Any loss of those customers or their contracts could have an adverse impact on our financial results. Competition. Our Crude Oil Logistics segment 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 and refinery demand; • reliability of service; • open credit; • logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars and towboats; and • long-term customer relationships. 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 350 producers at approximately 5,700 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, 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 segment benefits when the market is in contango, as increasing prices result in inventory value 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 11 backwardation, our 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 storage tank lease rates. To help mitigate the impact of changing prices, we enter into derivative instruments to hedge our inventory. Trade Names. Our Crude Oil Logistics segment operates primarily under the NGL Crude Logistics, NGL Crude Transportation, NGL Marine, NGL Crude Terminals and NGL Crude Cushing trade names. Liquids Logistics Overview . 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, 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. We employ a number of contractual and hedging strategies to minimize commodity exposure and maximize earnings stability of this segment. During the year ended March 31, 2022, we sold approximately 2.8 billion gallons of natural gas liquids, refined 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 sublease railcars to certain customers. Our owned and leased terminals and railcar fleet give us the opportunity to access markets throughout the United States, and to move product to locations where demand is highest. We provide transportation, storage, and throughput services to third parties at our facilities at Port Hudson, Louisiana and Chesapeake, Virginia. We purchase refined petroleum and renewable products primarily in the Gulf Coast, West Coast and Midwest regions of the United States and schedule them for delivery at various locations throughout the country. We conduct just-in-time sales at a nationwide network of terminals owned by third parties via rack spot sales or delivered 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 product 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. 12 The following table summarizes the location of our facilities and respective storage capacity and interconnects to those facilities. Storage Capacity (in gallons) Location Number of Facilities Own (1) Lease (2) Total Terminal Interconnects Virginia 2 20,720,000 — 20,720,000 Rail Facility; Marine Facility Arkansas 3 3,765,000 90,000 3,855,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Minnesota 1 1,829,000 — 1,829,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Missouri 2 1,770,000 — 1,770,000 Connected to Phillips66 Blue Line Pipeline Indiana 1 1,530,000 — 1,530,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Wisconsin 2 714,000 390,000 1,104,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Massachusetts 2 668,400 120,000 788,400 Rail Facility Louisiana 1 720,000 — 720,000 Truck Facility Washington 3 300,000 355,000 655,000 Rail Facility Illinois 1 480,000 — 480,000 Connected to Phillips66 Blue Line Pipeline Michigan 1 480,000 480,000 Connected to Ambassador Pipeline New York 1 — 270,000 270,000 Rail Facility Pennsylvania 1 180,000 — 180,000 Rail Facility Maine 1 — 120,000 120,000 Rail Facility Vermont 1 — 120,000 120,000 Rail Facility United States Total 23 33,156,400 1,465,000 34,621,400 Ontario, Canada 1 — 120,000 120,000 Truck Facility Canada Total 1 — 120,000 120,000 Total 24 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 gas 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. 13 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 upper Midwest and will expand our presence in Michigan, one of the top propane markets in the United States. We utilize a fleet of approximately 4,400 high-pressure and general purpose leased railcars of which 34 railcars are subleased by third parties. We lease 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 natural gas liquids and refined products storage facilities and interconnects to those facilities: Leased Storage Space (in gallons) Storage Facility Location Beginning April 1, 2022 At March 31, 2022 Storage Interconnects Kansas 56,700,000 56,700,000 Connected to Enterprise Mid-America Pipeline, NuStar Pipelines and ONEOK North System Pipeline; Rail Facility; Truck Facility Michigan 22,260,000 10,500,000 Rail Facility; Truck Facility Utah 8,400,000 22,050,000 Rail Facility Missouri 7,560,000 7,560,000 Truck Facility Arizona 7,056,000 7,056,000 Rail Facility; Truck Facility Texas 4,410,000 4,410,000 Connected to Enterprise Texas Eastern Products Pipeline; Truck Facility Mississippi 2,100,000 2,520,000 Connected to Enterprise Dixie Pipeline; Rail Facility Oregon 554,400 554,400 Connected to Kinder Morgan Pipeline and Olympic Pipeline United States Total 109,040,400 111,350,400 Ontario, Canada 8,467,200 15,750,000 Rail Facility Alberta, Canada 3,970,092 3,440,800 Connected to Cochin Pipeline; Rail Facility Canada Total 12,437,292 19,190,800 Total 121,477,692 130,541,200 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 the revenues of our Liquids Logistics 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. 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, and peaks in the Midwest during spring planting and fall harvest. Competition. Our Liquids Logistics segment faces significant competition from other natural gas liquids wholesalers, trading companies and companies involved in the natural gas liquids midstream industry (such as terminal and 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 . 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 refined 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 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 Considerations. 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 December 2019, the federal government passed a law to reinstate the tax credit retroactively to January 1, 2018, with the credit expiring on December 31, 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. Trade Names. Our Liquids Logistics segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Centennial Energy, NGL Crude Logistics and Centennial Gas Liquids trade names. Human Capital At March 31, 2022, we had 842 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. More 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 enrolled in the high-deductible medical plan; a dental plan; a vision plan; an Employee Assistance Plan including free counseling for employees and members of 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. These regulations may affect our businesses and the businesses of certain of our customers and suppliers. It is not possible to predict how or when regulations affecting our 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 has not impacted 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. Because our 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 compliance with the Jones 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 a myriad of federal, state and local laws and regulations relating to the protection of the environment. Existing regulatory structure shapes our decision-making and business activities in many ways, such as: • shaping decisions regarding what types of pollution-control equipment to deploy and how a facility should be designed; • informing decision-making regarding construction activities, such as where to locate and where not to locate a facility; e.g., locating construction activities away from sensitive environmental, cultural or historic areas, including 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; • informing decision-making regarding the timing of activities, for example, we will delay construction or system modification or upgrades during the issuance or renewal periods of certain permits; • informing decision-making pertaining to our approach to investigating, mitigating and remediating unplanned releases from our facilities and operations or attributable to former facilities or operations, as necessary and appropriate; and • shaping our decision-making about whether a facility or operation should be temporarily halted to address potential non-compliance with relevant permit requirements. Consideration of and compliance with relevant environmental regulatory requirements has led our business activities to be more sustainable while simultaneously mitigating exposure to long and short-term environmental risk. 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 crude 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. 17 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, 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. CERCLA, also known as the “Superfund” law, and similar state laws, impose liability 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. 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 into the environment. RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous wastes. Under a 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 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 thereby be subject to more rigorous and costly disposal requirements. Legislation has been proposed from time to time in Congress to regulate certain oil and natural gas wastes as “hazardous 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 crude oil is being or has been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, crude 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 the 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 Act of 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 an oil terminal, we could be subject to liability under the Oil Pollution 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 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 18 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 (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 SPCC plans for our facilities. Air Emissions. Our operations are subject to the CAA and comparable state and local laws and regulations, which regulate emissions of air pollutants from various industrial sources and mandate certain permitting, monitoring, recordkeeping and reporting requirements. The CAA and its implementing regulations may require that we obtain permits prior to the construction, modification or operation of certain projects or facilities expected to produce or increase air emissions above certain threshold levels, that we obtain and strictly comply with air permits containing emissions and operational limitations, or utilize specific emission control technologies to limit emissions, 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 make certain future capital expenditures for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. Water Discharges . The CWA 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 program requires appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a crude 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 CWA 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 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 CWA and analogous state laws and regulations. Underground Injection Control . The underground injection of 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 by state programs 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 to 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. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the formation to stimulate oil and gas 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 produced water generated from crude oil and natural gas production, including production employing hydraulic fracturing. 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 19 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 UIC 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 produced 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 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, in February 2021, the Climate Emergency Act of 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 require the President of the United States to declare a national climate emergency and 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 legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs 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 GHGs under existing provisions of the CAA. During the Obama Administration, the EPA finalized three rules that regulate GHG 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. During the Trump Administration, rulemaking was undertaken resulting in a substantial relaxation in the GHG NSPS’s requirements, including those relating to fugitive emissions, pneumatic pump standards, and closed vent system certification, among other things, which were finalized on August 13, 2020. The Biden 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, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program. The public 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 GHGs 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 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 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 GHG 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, while in other states, municipalities administer these laws. We 20 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 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 increased 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. In recent years, Congress has strengthened PHMSA’s safety authority and repeatedly extended it, most recently in the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020. Railcar Regulation We transport a significant portion of our natural gas liquids, crude oil and biodiesel via rail transportation, and we own and/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 transport activities, or efforts by local communities to restrict or limit rail traffic, 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 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 21 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 compliance with these standards to have a material adverse effect on our business. Available Information on our Website Our website address is 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 (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. 22 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 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. • 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. 23 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 distributions 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 distributions. 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 will have to fund our operations, 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: • the cost of crude oil, natural gas liquids, gasoline, diesel, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers; • the volume of produced 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 to 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 ABL Facility and the indentures governing our outstanding 7.5% senior notes due 2023, 6.125% senior notes due 2025, 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”), 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”); • 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 board of directors of our general partner decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet, among other things, the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes. This resulted in the suspension of the quarterly common unit distributions, which began with the quarter ended December 31, 2020, and all preferred unit distributions, which began with the quarter ended March 31, 2021. 24 Our substantial indebtedness may limit our flexibility to obtain financing and to pursue other business opportunities and our ability to service our debt could impact operations. At March 31, 2022, the face amount of our long-term debt was $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 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 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 may 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 ABL Facility and Indentures could adversely affect our business, financial position, results of operations, and the value of our common units. The ABL 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 will be permitted to make distributions to our unitholders once we meet certain defined metrics and 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 provisions of the ABL 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 these agreements could result in a default or an event of default that could enable our lenders, subject to the terms and conditions, 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 under our 2026 Senior Secured Notes and ABL Facility. If the 25 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. 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 impact our financing costs and our common unit price, our ability to issue equity or incur debt, 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. We 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, may 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, increases or decreases in interest rates may affect the yield requirements of investors who invest in our common units. 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 26 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 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 segments. The volume of water we process and crude oil we transport is driven in large part by the level of crude oil production in the areas in which we operate. Lower crude oil prices provide the producers with less incentive to 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 our profitability in our Water Solutions business is generated from the sale of crude oil that we recover when processing produced water, and lower crude oil prices have an adverse impact on these sales if not hedged. A decline in crude oil prices or a prolonged period of low crude oil prices could have an adverse effect on our businesses. Our profitability could be negatively impacted by price and inventory risk related to our business. The Crude Oil Logistics and Liquids Logistics 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 the ABL Facility, and we could be required to liquidate inventory that we have already presold. One of the strategies of our Liquids Logistics segment is to purchase refined products in the Gulf Coast and West Coast and transport the product on third-party pipelines for sale in the Southwest. 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 27 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, 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 customers for our services. These operations also face competition from transportation 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 produced water treatment businesses. 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 could reduce our revenues. Our business would be adversely affected if service at our principal storage facilities or on 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 common carrier pipelines we use would adversely affect our ability to obtain and deliver products. We transport natural gas liquids 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 28 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 sale of crude oil, condensate, natural gas liquids, gasoline , diesel, 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 timing risk. 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. 29 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. 30 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 31 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. 32 Risks Related to Regulatory Compliance Our sales of crude oil, condensate, natural gas liquids, gasoline , diesel, and biodiesel and related transportation and hedging activities, and our processing of 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 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. 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 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 produced water and hydrocarbons, such as crude oil, condensate, natural gas liquids, gasoline, diesel, 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 Logistics 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 33 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 produced 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 GHG emissions, or limiting GHG 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 34 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. 35 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 common practice within the oil and gas exploration and production process, including within those fields where our Water Solutions and Crude Oil Logistics segments operate. The practice of hydraulic fracturing is a well-stimulation technique utilized to facilitate the production of oil and natural gas and other hydrocarbon condensates from shale and tight conventional formations. The exploration and production process, including the practice of hydraulic fracturing, is subject to regulation by state and federal authorities. Jurisdiction 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 contributed to specific induced seismic 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, state regulatory agencies could request that we suspend operations at a disposal facility, pending further study of its potential impact on seismic activity. In one specific instance, we limited the water into a disposal well and 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. Some of our operations are subject to the jurisdiction of the FERC and other operations may become subject in the 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. 36 Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by state regulatory commissions, such as the 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. There are numerous laws and regulations regarding privacy and the storage, sharing, use, processing, transfer, disclosure and protection of personal data, the scope 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 may collect and use personal data. The effects of the CCPA potentially are far-reaching and may require us to modify our data processing practices and policies 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 additional data privacy compliance requirements that may impact our business, and establishes a regulatory agency dedicated to enforcing those requirements. It remains unclear how various provisions of the CCPA and CPRA will be interpreted and enforced. These and other data privacy laws and their interpretations continue to develop and may be inconsistent from jurisdiction to jurisdiction. Non-compliance with these laws could result in penalties or significant legal liability. Although we take reasonable efforts to comply with all applicable laws and regulations, there can be no assurance that we will not be subject to regulatory action, including fines, in the event of an incident. We or our third-party service providers could be adversely affected if legislation or regulations are expanded to require changes in our or our third-party service providers’ business practices or if governing jurisdictions interpret or implement their legislation or regulations in ways that negatively affect our or our third-party service providers’ business, results of operations or financial condition. 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. Risks Related 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. 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; 37 • 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. 38 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. 39 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. Our 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. 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. 40 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 organic 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. We currently have three series of Preferred Units outstanding. 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 41 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 Our 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. 42 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. 43 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 sells 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 44 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 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. 45 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 46 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 liquids 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. 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. 47 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, 48 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 obligations under the ABL Facility and indenture for the 2026 Senior Secured Notes are secured by liens and mortgages on substantially all of our real and personal property. We 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. 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 17 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. 49 PART II 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 June 1, 2022, there were approximately 100 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. 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 % (1) The maximum distribution of 48.1% does not include distributions that our general partner may receive on common units that it owns. 50 Restrictions on the Payment of Distributions 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. As the distributions for all of our 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 to our consolidated financial statements included in this Annual Report for a 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 summarizes the repurchase of common units during the three months ended March 31, 2022: Period Total Number of Common Units Purchased Average Price Paid Per Common Unit January 1-31, 2022 — $ — February 1-28, 2022 35,868 $ 2.00 March 1-31, 2022 — $ — 35,868 The common units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. Securities Authorized for Issuance Under Equity Compensation Plans In connection with the completion of our 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 Matters–Securities Authorized for Issuance Under Equity Compensation Plan,” which is incorporated by reference into this Item 5. Item 6. [Reserved] 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. 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 credit profile. These steps included the sale of the following: • 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 (“Gas Blending”) during the year ended March 31, 2020; and • Our interest in Sawtooth Caverns, LLC (“Sawtooth”) during the year ended March 31, 2022. 51 In addition, in our Water 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 our Liquids Logistics segment we 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 17 and Note 18 to our consolidated financial statements included in this Annual Report on Form 10-K (“Annual Report”). The sale of TPSL, Mid-Con and Gas Blending represented strategic shifts 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 TPSL, Mid-Con and Gas Blending have been classified as discontinued operations for the years ended March 31, 2021 and 2020. See Note 18 to our consolidated financial statements included in this Annual Report for a further discussion of 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 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. 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, 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 New 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, Low High At Period End 2022 $ 58.65 $ 123.70 $ 100.28 2021 (1) $ (37.63) $ 66.09 $ 59.16 2020 $ 20.09 $ 66.30 $ 20.48 (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 into 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 $304.3 million during the year ended March 31, 2021, which included impairment charges of $383.6 million related to the Extraction Oil & Gas, Inc. (“Extraction”) bankruptcy (see Note 17 to our consolidated financial statements included in this Annual Report). 53 Liquids Logistics 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, 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. 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 liquids 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 a 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, 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 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 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 2022 $ 0.78 $ 2.01 $ 1.71 2021 $ 0.28 $ 1.16 $ 0.98 2020 $ 0.19 $ 0.80 $ 0.29 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, Low High At Period End 2022 $ 81.95 $ 154.67 $ 133.96 2021 $ 21.43 $ 90.30 $ 82.04 2020 $ 17.30 $ 89.55 $ 24.07 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, Low High At Period End 2022 $ 74.44 $ 186.37 $ 155.03 2021 $ 25.64 $ 82.64 $ 74.39 2020 $ 40.08 $ 89.17 $ 42.51 54 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results. Our Liquids 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 a net loss of $11.8 million related to the sale of another terminal. Our Liquids Logistics segment generated operating income of $70.4 million during the year ended March 31, 2021. Consolidated Results of Operations The following table summarizes our consolidated statements of operations for the periods indicated: Year Ended March 31, 2022 2021 2020 (in thousands) Revenues $ 7,947,915 $ 5,227,023 $ 7,584,000 Cost of sales 7,139,312 4,493,822 6,604,383 Operating expenses 285,535 254,562 332,993 General and administrative expense 63,546 70,468 113,664 Depreciation and amortization 288,720 317,227 265,312 Loss on disposal or impairment of assets, net 94,254 475,436 261,786 Revaluation of liabilities (6,495) 6,261 9,194 Operating income (loss) 83,043 (390,753) (3,332) Equity in earnings of unconsolidated entities 1,400 1,938 1,291 Interest expense (271,640) (198,799) (181,184) Gain (loss) on early extinguishment of liabilities, net 1,813 (16,692) 1,341 Other income (expense), net 2,254 (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) Items Impacting the Comparability of Our Financial Results Our current and future results of operations may not be comparable to our historical results of operations for the periods presented due to acquisitions, dispositions and other transactions. Acquisitions and Dispositions We completed several acquisitions and dispositions during the years ended March 31, 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 sold our approximately 71.5% interest in Sawtooth to a group of buyers (see Note 17 to our consolidated financial statements included in this Annual Report). 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 termination point near Marysville in St. Clair County, Michigan. During the year ended March 31, 2021, we sold certain permits, land and a saltwater disposal facility to a third-party (see Note 17 to our consolidated financial statements included in this Annual Report). Seasonality Seasonality impacts our Liquids Logistics segment. Consequently, for 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 55 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 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, 2022. Segment Operating Results for the Years Ended March 31, 2022 and 2021 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated. Year Ended March 31, 2022 2021 Change (in thousands, except per barrel and per day amounts) Revenues: Water disposal service fees $ 397,128 $ 308,511 $ 88,617 Sale of recovered crude oil 77,203 28,599 48,604 Recycled water 11,343 3,015 8,328 Other revenues 59,192 30,861 28,331 Total revenues 544,866 370,986 173,880 Expenses: Cost of sales-excluding impact of derivatives 26,340 2,557 23,783 Derivative loss 7,640 7,065 575 Operating expenses 175,022 142,371 32,651 General and administrative expenses 7,352 6,403 949 Depreciation and amortization expense 214,558 222,107 (7,549) Loss on disposal or impairment of assets, net 25,598 76,942 (51,344) Revaluation of liabilities (6,495) 6,261 (12,756) Total expenses 450,015 463,706 (13,691) Segment operating income (loss) $ 94,851 $ (92,720) $ 187,571 Produced water processed (barrels per day) Delaware Basin 1,531,830 1,148,582 383,248 Eagle Ford Basin 99,298 78,397 20,901 DJ Basin 142,611 111,016 31,595 Other Basins 24,179 26,596 (2,417) Total 1,797,918 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 produced water 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 to an increase in produced water volumes processed as a result of increased crude oil production driven by higher crude oil prices and completion activity, primarily in the Delaware Basin. This was partially offset by lower service fees received per barrel due to 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 number of wells completed 56 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 customers’ completion activities. The increase was due primarily to increasing demand for water to be used in completions, driven by an increase in drilling and completion activity primarily in the Delaware Basin, and our customers transition from brackish non-potable water to recycled water. 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, 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, 2022 2021 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 2,432,393 $ 1,574,699 $ 857,694 Crude oil transportation and other 84,171 153,588 (69,417) Total revenues (1) 2,516,564 1,728,287 788,277 Expenses: Cost of sales-excluding impact of derivatives 2,271,973 1,473,330 798,643 Derivative loss 92,027 49,314 42,713 Operating expenses 54,606 56,918 (2,312) General and administrative expenses 7,537 8,038 (501) Depreciation and amortization expense 48,489 60,874 (12,385) (Gain) loss on disposal or impairment of assets, net (3,101) 384,143 (387,244) Total expenses 2,471,531 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. 58 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). 59 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated: Year Ended March 31, 2022 2021 Change (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 derivatives 1,876,728 1,108,493 768,235 Derivative loss 2,907 930 1,977 Product margin 20,263 14,664 5,599 Propane sales: Revenues (1) 1,325,941 1,027,582 298,359 Cost of sales-excluding impact of derivatives 1,313,765 949,402 364,363 Derivative (gain) loss (20,519) 10,994 (31,513) Product margin 32,695 67,186 (34,491) Butane sales: Revenues (1) 863,348 517,857 345,491 Cost of sales-excluding impact of derivatives 794,180 469,394 324,786 Derivative loss 18,690 22,353 (3,663) Product margin 50,478 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 derivatives 748,392 424,191 324,201 Derivative loss (gain) 15,812 (7,078) 22,890 Product margin 26,921 29,631 (2,710) Service revenues: Revenues (1) 16,200 33,915 (17,715) Cost of sales 1,404 4,751 (3,347) Product margin 14,796 29,164 (14,368) Expenses: Operating expenses 55,907 55,273 634 General and administrative expenses 7,166 8,507 (1,341) Depreciation and amortization expense 18,714 29,184 (10,470) Loss on disposal or impairment of assets, net 71,807 3,350 68,457 Total expenses 153,594 96,314 57,280 Segment operating (loss) income $ (8,441) $ 70,441 $ (78,882) 60 Year Ended March 31, 2022 2021 Change (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 61 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 million of 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 million of 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. 62 Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands) Other revenues: Revenues $ — $ 1,255 $ (1,255) Cost of sales — 1,816 (1,816) Loss — (561) 561 Expenses: General and administrative expenses 41,491 47,520 (6,029) Depreciation and amortization expense 6,959 5,062 1,897 (Gain) loss on disposal or impairment of assets, net (50) 11,001 (11,051) Total expenses 48,400 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, 2022 2021 Change (in thousands) Senior secured notes $ 153,750 $ 24,344 $ 129,406 Senior unsecured notes 87,766 96,711 (8,945) Amortization of debt issuance costs 16,960 13,420 3,540 Revolving credit facility 10,077 46,500 (36,423) Other 3,087 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). 63 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. 64 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, 2021 2020 Change (in thousands, except per barrel and per day amounts) Revenues: Water disposal service fees $ 308,511 $ 305,124 $ 3,387 Sale of recovered crude oil 28,599 59,445 (30,846) Recycled water 3,015 705 2,310 Other revenues 30,861 56,785 (25,924) Total revenues 370,986 422,059 (51,073) Expenses: Cost of sales-excluding impact of derivatives 2,557 5,511 (2,954) Derivative loss (gain) 7,065 (39,381) 46,446 Operating expenses 142,371 192,987 (50,616) General and administrative expenses 6,403 7,939 (1,536) Depreciation and amortization expense 222,107 163,588 58,519 Loss on disposal or impairment of assets, net 76,942 255,285 (178,343) Revaluation of liabilities 6,261 9,194 (2,933) Total expenses 463,706 595,123 (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 Basin 78,397 246,784 (168,387) DJ Basin 111,016 164,936 (53,920) Other Basins 26,596 61,091 (34,495) Total 1,364,591 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 produced water 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 produced water 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. 66 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, 2021 2020 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 1,574,699 $ 2,383,812 $ (809,113) Crude oil transportation and other 153,588 184,129 (30,541) Total revenues (1) 1,728,287 2,567,941 (839,654) Expenses: Cost of sales-excluding impact of derivatives 1,473,330 2,347,863 (874,533) Derivative loss (gain) 49,314 (35,736) 85,050 Operating expenses 56,918 61,708 (4,790) General and administrative expenses 8,038 6,723 1,315 Depreciation and amortization expense 60,874 70,759 (9,885) Loss (gain) on disposal or impairment of assets, net 384,143 (1,144) 385,287 Total expenses 2,032,617 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 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 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. 68 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated: Year Ended March 31, 2021 2020 Change (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 margin 14,664 30,038 (15,374) Propane sales: Revenues (1) 1,027,582 846,756 180,826 Cost of sales-excluding impact of derivatives 949,402 766,521 182,881 Derivative loss 10,994 3,536 7,458 Product margin 67,186 76,699 (9,513) Butane sales: Revenues (1) 517,857 564,016 (46,159) Cost of sales-excluding impact of derivatives 469,394 486,777 (17,383) Derivative loss (gain) 22,353 (8,288) 30,641 Product margin 26,110 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 derivatives 424,191 732,967 (308,776) Derivative gain (7,078) (2,846) (4,232) Product margin 29,631 45,337 (15,706) Service revenues: Revenues (1) 33,915 40,216 (6,301) Cost of sales 4,751 9,207 (4,456) Product margin 29,164 31,009 (1,845) Expenses: Operating expenses 55,273 77,980 (22,707) General and administrative expenses 8,507 12,644 (4,137) Depreciation and amortization expense 29,184 27,930 1,254 Loss on disposal or impairment of assets, net 3,350 7,645 (4,295) Total expenses 96,314 126,199 (29,885) Segment operating income $ 70,441 $ 142,411 $ (71,970) 69 Year Ended March 31, 2021 2020 Change (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. 70 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. 71 Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2021 2020 Change (in thousands) Other revenues: Revenues $ 1,255 $ 1,038 $ 217 Cost of sales 1,816 1,774 42 Loss (561) (736) 175 Expenses: Operating expenses — 318 (318) General and administrative expenses 47,520 86,358 (38,838) Depreciation and amortization expense 5,062 3,035 2,027 Loss on disposal or impairment of assets, net 11,001 — 11,001 Total expenses 63,583 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, 2021 2020 Change (in thousands) Senior unsecured notes $ 96,711 $ 102,289 $ (5,578) Revolving credit facility 46,500 57,470 (10,970) Senior secured notes 24,344 — 24,344 Amortization of debt issuance costs 13,420 10,901 2,519 Other 17,824 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). 72 (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. 73 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, 2022 2021 2020 (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 expense 271,689 198,823 181,357 Income tax expense (benefit) 971 (3,444) 365 Depreciation and amortization 287,943 314,476 265,147 EBITDA 375,847 (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 adjustments 10,862 (30,102) 31,202 Loss on disposal or impairment of assets, net 94,059 476,601 464,483 (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. 74 (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, 2022 2021 2020 (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 interests 1,826 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 expense 16,960 13,419 10,901 Amortization of royalty expense recorded to operating expense 247 247 286 Depreciation and amortization of unconsolidated entities (768) (756) (561) Depreciation and amortization attributable to noncontrolling interests 1,826 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, 2022 2021 2020 (in thousands) Interest expense per EBITDA table $ 271,689 $ 198,823 $ 181,357 Interest expense attributable to noncontrolling interests 16 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, 2021 2020 (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 Logistics Corporate and Other Consolidated (in thousands) Operating income (loss) $ 94,851 $ 45,033 $ (8,441) $ (48,400) $ 83,043 Depreciation and amortization 214,558 48,489 18,714 6,959 288,720 Amortization recorded to cost of sales — — 281 — 281 Net unrealized losses (gains) on derivatives 11,652 (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, net 25,598 (3,101) 71,807 (50) 94,254 Equity-based compensation expense — — — (1,052) (1,052) Acquisition expense 4 — — 63 67 Other income, net 718 353 711 472 2,254 Adjusted EBITDA attributable to unconsolidated entities 2,363 — 14 (145) 2,232 Adjusted EBITDA attributable to noncontrolling interest (2,212) — (528) — (2,740) Revaluation of liabilities (6,495) — — — (6,495) Other 921 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 Logistics Corporate and Other Continuing Operations Discontinued 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 amortization 222,107 60,874 29,184 5,062 317,227 — 317,227 Amortization recorded to cost of sales — — 307 — 307 — 307 Net unrealized losses (gains) on derivatives 24,500 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, net 76,942 384,143 3,350 11,001 475,436 — 475,436 Equity-based compensation expense — — — 6,727 6,727 — 6,727 Acquisition expense 27 — — 1,684 1,711 — 1,711 Other income (expense), net 266 1,565 1,301 (39,635) (36,503) — (36,503) Adjusted EBITDA attributable to unconsolidated entities 3,019 — (3) (252) 2,764 — 2,764 Adjusted EBITDA attributable to noncontrolling interest (1,647) — (2,887) — (4,534) — (4,534) Revaluation of liabilities 6,261 — — — 6,261 — 6,261 Class D Preferred Unitholder consent fee — — — 40,000 40,000 — 40,000 Intersegment transactions (1) — — (27) — (27) — (27) Other 2,751 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 Logistics Corporate and Other Continuing Operations Discontinued 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 amortization 163,588 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, net 255,285 (1,144) 7,645 — 261,786 — 261,786 Equity-based compensation expense — — — 26,510 26,510 — 26,510 Acquisition expense 4,079 — — 15,643 19,722 — 19,722 Other (expense) income, net (448) 717 21 1,394 1,684 — 1,684 Adjusted EBITDA attributable to unconsolidated entities 2,152 — 24 (263) 1,913 — 1,913 Adjusted EBITDA attributable to noncontrolling interest (1,210) — (1,842) — (3,052) — (3,052) Revaluation of liabilities 9,194 — — — 9,194 — 9,194 Intersegment transactions (1) — — 2,099 — 2,099 — 2,099 Other 2,607 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 use by other entities within our consolidated group. All of our wholly-owned operating subsidiaries participate in this program. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us. Short-Term Liquidity 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 ABL Facility. 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. 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 (see Note 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 linefill and has been prepared on the accrual basis), acquisitions and other investments for the periods indicated. Capital Expenditures Other Year Ended March 31, Expansion (1) Maintenance Acquisitions Investments (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 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. The board of directors of our general partner expects to evaluate the reinstatement of the common unit and all preferred unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, upcoming debt maturities, capital expenditures and the overall performance of our businesses. 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 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 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): 2022 2021 2020 (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 81 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 17 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 decrease 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 quarterly common unit and preferred unit distributions; 82 • $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 83 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. 84 Environmental Legislation See Part I, Item 1–“Business–Government Regulation–Greenhouse Gas Regulation” 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 Estimates 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. 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. 85 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 86 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 87 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; 88 • 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. 89 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. 90 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 91 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. 92 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. Name Age Position with NGL Energy Holdings LLC H. Michael Krimbill 68 Chief Executive Officer and Director Linda J. Bridges 38 Executive Vice President and Chief Financial Officer John A. Ciolek 58 Executive Vice President, Strategic Initiatives Kurston P. McMurray 50 Executive Vice President and General Counsel and Secretary Lawrence J. Thuillier 51 Chief Accounting Officer Shawn W. Coady 60 Director James M. Collingsworth 67 Director Stephen L. Cropper 72 Director Bryan K. Guderian 62 Director John T. Raymond 51 Director Derek S. Reiners 51 Director Randall S. Wade 52 Director 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 Gro