NGL Energy Partners LP 10-K

ngl-20250331 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, 2025 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 1300 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 Symbol(s) 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. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 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, 2024 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 ($ 4.50 per Common Unit) was $ 465.3 million. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates. At May 27, 2025, there were 132,012,766 common units issued and outstanding. TABLE OF CONTENTS PART I Item 1. Business 3 Item 1A. Risk Factors 21 Item 1B. Unresolved Staff Comments 48 Item 1C. Cybersecurity 48 Item 2. Properties 50 Item 3. Legal Proceedings 50 Item 4. Mine Safety Disclosures 50 PART II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities 51 Item 6. [Reserved] 52 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 52 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 83 Item 8. Financial Statements and Supplementary Data 85 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 85 Item 9A. Controls and Procedures 85 Item 9B. Other Information 87 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 87 PART III Item 10. Directors, Executive Officers and Corporate Governance 87 Item 11. Executive Compensation 91 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters 97 Item 13. Certain Relationships and Related Transactions, and Director Independence 99 Item 14. Principal Accountant Fees and Services 102 PART IV Item 15. Exhibit and Financial Statement Schedules 103 Item 16. Form 10-K Summary 106 i Forward-Looking Statements This Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) beliefs and those of our general partner (“GP”), 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 GP believe such forward-looking statements are reasonable, neither we nor our GP 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, and energy prices generally; • the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, and diesel; • 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, and diesel; • 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; • the 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, the treatment of flowback and produced water, seismic activity, and drilling and right-of-way access on federal and state lands; • delays or restrictions in obtaining, utilizing or maintaining permits and/or rights-of-way by us or our customers; • 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 and natural gas liquids industries and competition from other markets; • loss of key personnel; • the impact of competition on our operations, including our 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; • inflation, interest rates, tariffs and general economic conditions (including recessions and other future disruptions and volatility in the global credit markets, as well as the impact of these events on customers and suppliers); • the nonpayment, nonperformance or bankruptcy by our counterparties; • the availability and cost of capital and our ability to access certain capital sources; • a deterioration of the credit and capital markets; 1 • the ability to successfully identify and complete accretive organic growth projects; • the costs and effects of legal and administrative proceedings; • changes in general economic conditions, including market and macroeconomic disruptions resulting from global pandemics and related governmental responses, and international military conflicts (such as the war in Ukraine and conflicts in the Middle East); • 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, natural gas and natural gas liquids; • information technology risks including the risk from cyberattacks, cybersecurity breaches, and other disruptions to our information systems; 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,” “we,” “us,” “our,” or the “Partnership” 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 (“GP”), (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 43 individuals and entities that own all of the outstanding membership interests in our GP. We have presented operational data in Part I, Item 1–“Business” for the year ended March 31, 2025. Unless otherwise indicated, this data is as of March 31, 2025. Item 1. Business Overview We are a diversified midstream energy partnership that transports, treats, recycles and disposes of produced and flowback 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 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 with acreage dedications and which include minimum volume commitments on our storage tanks and owned and leased pipelines. • Our Liquids Logistics segment conducts supply operations for natural gas liquids to commercial, retail and industrial customers across the United States and Canada. These operations are conducted through our five owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars (updated for the transactions discussed below). We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia and we also own a propane pipeline in Michigan. 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. Sale of Refined Products Business and Exiting Biodiesel Business As of March 31, 2025, we completed winding down our biodiesel business (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). On March 17, 2025, we signed a purchase and sale agreement to sell our refined products business, including certain working capital items, to a third-party (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). This sale closed on April 30, 2025. The sale of our refined products business and winding down of our biodiesel business represent a strategic shift in our operations and will have a significant effect on our operations and financial results going forward. Accordingly, the results of operations and cash flows for our refined products and biodiesel businesses within our Liquids Logistics segment have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted in the consolidated statements of operations and consolidated statements of cash flows. In addition, the assets and liabilities related to our refined products and biodiesel businesses have been classified as either held for sale or discontinued operations within our 3 March 31, 2025 and 2024 consolidated balance sheets (see Note 18 to our consolidated financial statements included in this Annual Report for a further discussion). Sale of Certain Natural Gas Liquids Terminals and Most of Our Wholesale Propane Business On February 5, 2025, we signed a purchase and sale agreement to sell 17 of our natural gas liquids terminals, most of our wholesale propane business, our interest in an unconsolidated entity and working capital to a third-party (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). This sale closed on April 30, 2025. The assets and liabilities of this portion of our Liquids Logistics segment have been classified as held for sale within our March 31, 2025 consolidated balance sheet (see Note 18 to our consolidated financial statements included in this Annual Report for a further discussion). As this sale transaction did not represent a strategic shift that will have a major effect on our operations or financial results, operations related to this portion of our Liquids Logistics segment have not been classified as discontinued operations. Business Repositioning Over the past several years, we have undertaken a number of important strategic actions in an effort to capitalize on the Partnership’s core areas of competitive strength and focus on generating stable, growing and predictable cash flows, while improving our credit profile. We believe our actions have simplified our business mix and have allowed us to focus on what we believe are the core areas of our business and improved our overall financial position. 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 1 and Note 17 to our consolidated financial statements included in this current Annual Report and our Annual Reports on Form 10-K for the years ended March 31, 2024 and 2023 . Debt Refinancing On February 2, 2024, we closed a debt refinancing transaction of $2.9 billion. The refinancing consisted of a private offering of $2.2 billion of senior secured notes, which includes $900.0 million of 8.125% senior secured notes due 2029 (“2029 Senior Secured Notes”) and $1.3 billion of 8.375% senior secured notes due 2032 (“2032 Senior Secured Notes”). We also entered into a new seven-year $700.0 million senior secured term loan “B” credit facility (“Term Loan B”). In addition, in connection with the closing of the refinancing, our asset-based revolving credit facility (“ABL Facility”) was amended to extend the maturity and to make certain other changes to the terms thereof. For additional information related to the 2029 Senior Secured Notes, 2032 Senior Secured Notes, Term Loan B and ABL Facility, 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 May 29, 2025: 5 Organizational Chart The following chart provides a summarized overview of our legal entity structure at May 29, 2025: (1) Includes (i) NGL Water Solutions, LLC, which includes the operations of our Water Solutions segment, (ii) NGL Crude Assets and Marketing, LLC, which includes the operations of our Crude Oil Logistics segment and (iii) NGL Liquids, LLC, which includes the remaining operations of 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 managing 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 9.00% Class D Preferred Units (“Class D Preferred Units”) and debt, lower our leverage and maintain sufficient liquidity to finance growth projects and eventually reinstate the payment of common unit 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. • Building a midstream master limited partnership focusing on providing water solutions to upstream customers. We continue to enhance our ability to transport produced water from the wellhead to treatment for disposal, recycle, or discharge. To a lesser extent, we move crude oil from the wellhead to refineries, and natural gas liquids from processing plants and supply hubs to end users. • Operating 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. • Focusing 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 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 or minimum volume commitments from producers. • Achieving 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 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 located in the DJ Basin and Cushing, Oklahoma. Our strategically deployed terminals, as well as our owned and contracted pipeline capacity, provide access to producers in the DJ Basin. These operations are supported by certain long-term, fixed rate contracts and acreage dedications with producers, refiners and marketers and include minimum volume commitments on our owned and leased pipelines and storage tanks. • 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 natural gas liquid supply terminals, propane pipeline in Michigan, large leased railcar fleet, shipper status on common carrier pipelines, and 7 leased storage enable us to be a preferred purchaser and seller of butane and other 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 contracted 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 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 and evaluating 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 DJ Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 958.3 million barrels of produced water across its areas of operation during the year ended March 31, 2025, we believe that we are the largest independent produced water transportation and disposal company in the United States. 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 over 800 miles of newly-built, in-service large diameter produced water pipelines connected to 58 active saltwater disposal facilities and 132 active disposal wells. We currently have approximately 765,000 acres dedicated to our Northern Delaware system under long-term agreements providing a multi-decade drilling inventory and significant growth opportunity. In addition, we have several minimum volume commitments and other commercial agreements covering the Delaware, DJ and Eagle Ford 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. During the quarter ended December 31, 2024, we completed the expansion of our Lea County Express Pipeline System (“LEX II Expansion”) from a capacity of 140,000 barrels of water per day to 340,000 barrels of water per day. The addition of a second large-diameter pipeline, disposal wells, and facilities has expanded the capabilities of our existing produced water super-system and created a significantly larger outlet for produced water disposal within the Delaware Basin. The 27-mile, 30-inch produced water pipeline will transport water to areas outside the core of the basin thereby further diversifying the geographic location of our disposal operations. The LEX II Expansion is fully underwritten by a minimum volume commitment contract that includes an acreage dedication extension with an investment grade oil and gas producer. The LEX II Expansion includes an incremental increase in committed acreage and volumes under dedication from the producer. Additionally, the LEX II Expansion is expandable up to 500,000 barrels of water per day. As part of our operations, we also recycle water, which includes the sale of produced water and recycled water for use in our customers’ completion activities. During the year ended March 31, 2025, we sold approximately 42.4 million barrels of recycled water. 8 Operations. 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, 2025, 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 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 useful lives of the wells. We own 90 water treatment and disposal facilities, including 194 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 (1) Wells Own (2) Lease (3) Total Delaware Basin (4) - Texas and New Mexico 58 132 1,369,000 3,767,300 5,136,300 Eagle Ford Basin (4)(5) - Texas 18 31 424,000 362,000 786,000 DJ Basin - Colorado 13 30 373,000 142,500 515,500 Other Basins - Texas 1 1 20,000 — 20,000 Total - All Facilities 90 194 2,186,000 4,271,800 6,457,800 (1) We own the land on which 39 of the 90 water treatment and disposal facilities are located and we either have easements or lease the land on which the remaining water treatment and disposal facilities are located. (2) These facilities are located on lands we own. (3) These facilities are located on lands we lease. (4) Certain facilities can dispose of both produced water and solids such as tank bottoms, drilling fluids and drilling muds. (5) Includes one facility with a permitted processing capacity of 40,000 barrels per day in which we own a 75% interest and two facilities, one with a permitted processing capacity of 60,000 barrels per day and the other with a permitted processing capacity of 65,000 barrels per day, in which we own a 50% interest. On March 31, 2023, we sold certain saltwater disposal assets in the Midland Basin (see Note 17 to our consolidated financial statements included in this Annual Report). On July 25, 2023, we entered into an agreement in which we terminated a minimum volume water disposal contract and sold certain saltwater disposal assets and intangible assets in the Pinedale Anticline Basin (see Note 17 to our consolidated financial statements included in this Annual Report). On April 5, 2024, we sold approximately 122,250 acres of real estate on two ranches located in Eddy and Lea Counties, New Mexico. In addition, the assets and liabilities related to these ranches were classified as held for sale within our March 31, 2024 consolidated balance sheet (see Note 17 to our consolidated financial statements included in this Annual Report). 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, 2025, 73% of the revenues of our Water Solutions segment were generated from our ten largest customers of the segment. Additionally, certain key customers of the Water Solutions segment contribute significantly to the cash flows and profitability of the Partnership. Any loss of those customers or their contracts could have an adverse impact on our financial results. 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 9 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 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 under the NGL Water Solutions trade name. 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 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 with acreage dedications and which include minimum volume commitments on our storage tanks and owned and leased pipelines. Our operations are concentrated in and around four prolific crude oil producing regions in the United States, including the DJ Basin in Colorado, the Delaware 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, a 550-mile pipeline that transports crude oil from its origin in Weld County, Colorado to our terminal in Cushing, Oklahoma. The main line portion of this pipeline is comprised of a 34.09% undivided interest with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) in which we have ownership of 150,000 barrels per day of capacity. During the year ended March 31, 2025, approximately 61,000 barrels per day of crude oil were transported on the Grand Mesa Pipeline. Operating costs associated with the Grand Mesa Pipeline 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 oil volumes of different types and grades and store them until they are ready for transfer to the Grand Mesa Pipeline. The Lucerne terminal has approximately 950,000 barrels of storage and a 12 bay truck loading facility. The Riverside terminal has approximately 20,000 barrels of storage and a four bay truck loading facility. Through our ownership 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 quality management building, 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 the 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 Light Sweet Crude Oil futures contracts. We own and operate a crude oil marine terminal in Point Comfort, Texas with 370,000 barrels of storage capacity and six off-loading LACTs. Our tanks connect to three docks at the port (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, as well as our owned and contracted pipeline capacity, provide access to producers in the DJ Basin. 10 We currently transport crude oil on the Grand Mesa Pipeline, which is described above, and 19 other common carrier pipelines owned by third parties. As of May 29, 2025, all railcars have been sold or are under purchase and sale agreements. We also own 25 pipeline injection stations, the locations of which are summarized below. State Number of Pipeline Injection Stations Texas 11 New Mexico 6 Oklahoma 5 Kansas 3 Total 25 See Note 17 to our consolidated financial statements included in this Annual Report for all related dispositions in the current and prior years for the Crude Oil Logistics segment. Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2025, 79% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment. Additionally, certain key customers of the Crude Oil Logistics segment contribute significantly to the cash flows and profitability of the Partnership. 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 pipeline; 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 80 producers at 496 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 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. 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 higher 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 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 Assets and Marketing, NGL Crude Transportation, NGL Crude Terminals and NGL Crude Cushing trade names. 11 Liquids Logistics Overview . Our Liquids Logistics segment conducts supply operations for natural gas liquids to commercial, retail and industrial customers across the United States and Canada. These operations are conducted through our five 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 we also own a propane pipeline in Michigan. 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. 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, 2025, we sold approximately 1.6 billion gallons of natural gas liquids or 4.26 million gallons (approximately 101,000 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 in Port Hudson, Louisiana, Chesapeake, Virginia and Shelton, Washington. 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 20,888,000 — 20,888,000 Rail, Truck and Marine Facility Louisiana 1 720,000 — 720,000 Truck Facility Michigan 1 480,000 — 480,000 Truck and Pipeline Facility Washington 1 — 120,000 120,000 Rail and Truck Facility Total 5 22,088,000 120,000 22,208,000 (1) These facilities are located on lands we own. (2) These facilities are located on lands we lease. We own the land on which four of the five natural gas liquids terminals are located and we lease the land on which the remaining terminal is located. We own a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a marine export/import terminal in Chesapeake, Virginia. The Port Hudson terminal is located near Baton Rouge, Louisiana, and is in 12 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 20,408,000 gallons. See Note 1 and Note 17 to our consolidated financial statements included in this Annual Report for all related dispositions in the current and prior years for the Liquids Logistics segment. We own 28 transloading units, which enable transfer of product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most economical to transfer product at sites which otherwise would be out of reach of this product. 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. The Wheeler propane terminal, in central Michigan, is located at the mid-point of the pipeline. We utilize a fleet of approximately 3,300 high-pressure and general purpose leased railcars of which 102 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 storage facilities and interconnects to those facilities: Leased Storage Space (in gallons) Storage Facility Location Beginning April 1, 2025 At March 31, 2025 Storage Interconnects Michigan 10,500,000 21,000,000 Rail and Truck Facility Mississippi 8,400,000 3,150,000 Pipeline and Rail Facility Utah 5,880,000 5,250,000 Rail Facility Texas 210,000 210,000 Pipeline and Rail Facility United States Total 24,990,000 29,610,000 Alberta, Canada 1,323,420 1,323,420 Pipeline and Rail Facility Ontario, Canada — 8,467,200 Rail Facility Canada Total 1,323,420 9,790,620 Total 26,313,420 39,400,620 Customers . Our customers include national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. During the year ended March 31, 2025, 36% of the revenues of our Liquids Logistics segment were generated from our ten largest customers of the segment. Additionally, certain key customers of the Liquids Logistics segment contribute significantly to the cash flows and profitability of the Partnership. Any loss of those customers or their contracts could have an adverse impact on our financial results. 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, while butane seasonality is driven primarily by winter gasoline blending. 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. 13 Competition. Our Liquids Logistics segment faces 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; • 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. 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 market risk policy. 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 commodity price exposure 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. We can 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. Trade Names. Our Liquids Logistics segment operates primarily under the Centennial Energy, Centennial Gas Liquids and NGL Supply Terminal Company trade names. Human Capital At March 31, 2025, we had 569 employees in 27 states and Canada. Of those employees, 212 provide work primarily for our Water Solutions segment, 56 provide work primarily for our Crude Oil Logistics segment, 139 provide work primarily for our Liquids Logistics segment, and 162 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 minimum wage for all regular, full-time employees. More than 96% of our eligible employees participated in the NGL 401(k) Plan in fiscal year 2025. As of January 1, 2023, we shortened the NGL 401(k) eligibility period from the first day after six months of employment to the first day of the month after three months of employment. 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: 14 • Advises on safety and industrial hygiene regulatory requirements and best practices; • Develops safety procedures and guidelines; • Conducts safety inspections; • Advises on strategies to improve health and safety 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 (“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 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. 15 Environmental Regulation General. Our operations are subject to federal, state and local laws and regulations relating to the protection of the environment. Existing regulatory requirements inform our decision-making and business activities in many ways, such as: • informing 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 • informing our decision-making about whether a facility or operation should be temporarily halted to address potential non-compliance with relevant permit requirements. 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/or 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 released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect human health and the environment and to commit greater financial and other resources to inspection, compliance and enforcement activities. 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. 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 hazardous substances and waste, 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 use, handling, storage, treatment, transport and disposal of solid and hazardous wastes; (ii) subject our operations to certain permitting, registration and reporting 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 any violation of environmental laws and regulations or 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 (“EPCRA”), the Clean Water Act (“CWA”), the Safe Drinking Water Act, the Oil Spills Prevention and Preparedness Regulations, each as amended, 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 liable for releases of hazardous substances under CERCLA may be subject to strict and/or 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. 16 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 United States Environmental Protection Agency (“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. Wastes containing naturally occurring radioactive materials (“NORM”) and technologically enhanced naturally occurring radioactive material (“TENORM”) may also be generated or concentrated, respectively, in connection with our operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM or concentrations of TENORM, which may be present in oilfield wastes. NORM and TENORM are subject primarily to individual state radiation control regulations. Texas, New Mexico and Colorado have enacted regulations governing the handling, treatment, storage and disposal of NORM and TENORM. In addition, NORM and TENORM handling and management activities are governed by regulations promulgated by the federal Occupational Safety and Health Act (“OSHA”). These state and OSHA regulations impose certain requirements concerning worker protection, the treatment, storage and disposal of NORM and TENORM waste, the management of waste piles, containers and tanks containing NORM and TENORM, as well as restrictions on the uses of land with NORM or TENORM contamination. 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, including Per- and Polyfluoroalkyl Substances (“PFAS”), 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 or released 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 . 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 either a Spill Prevention Control and Countermeasure (“SPCC”) plan or Facility Response Plan (“FRP”), depending on the site specific substantial harm criteria, 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 into or upon the navigable waters of the United States. SPCC and FRP 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 or FRP-regulated is required to prepare a written, site-specific plan, which details how a facility’s operations comply with the spill prevention and control requirements. To be in compliance, the facility’s 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 plan and train personnel in its execution. Where applicable, we strive to maintain and implement SPCC plans and/or FRP plans for our facilities. Violation of SPCC and FRC requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. 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. Under a delegation of authority from the EPA, most states administer some or all of the provisions of the CAA, sometimes in conjunction with their own, more stringent requirements. The CAA and its implementing regulations on the federal and state level may require that we obtain permits prior to the construction, modification or operation of certain projects or facilities expected to emit 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 17 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 unless permitted to do so. 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 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 or other discharges 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 (“UIC”) 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 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 segment 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 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. Endangered Species . The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”) and the Bald and Golden Eagle Protection Act (“BGEPA”). To the degree that species listed under the ESA or similar state laws, or are protected under the MBTA or BGEPA, live, breed or nest in or migrate through the areas where we or our oil and gas producing customers operate, our and our customers’ abilities to conduct or expand operations and construct 18 facilities could be limited or be forced to incur material additional costs. Moreover, our customers’ drilling activities may be delayed, restricted, or cancelled in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. In addition, the U.S. Fish and Wildlife Service (“USFWS”) may make determinations on the listing of currently unlisted species as endangered or threatened under the ESA. For example, in May 2024, the dunes sagebrush lizard, which is found in areas where we operate, was listed as endangered under the ESA which sparked allegations that the designation occurred to hinder fossil fuel production. This resulted in a federal lawsuit filed in the Western District of Texas aimed at overturning the designation. In addition, the lesser prairie-chicken, which can also be found in areas where we operate, was listed under the ESA effective March 27, 2023. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and gas producing customers’ operations to become subject to operating restrictions or bans and limit future development activity in affected areas. The USFWS and similar state agencies may also designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state, and private lands. 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. For example, on October 7, 2023, California Governor Gavin Newsom signed SB 253, the Climate Corporate Data Accountability Act, and SB 261, the Climate-Related Financial Risk Act. These two bills apply to companies doing business in California and require disclosure of, among certain other climate-related financial risk information, Scope 1 and 2 GHG emissions, beginning in 2026 (on prior fiscal year information), and Scope 3 GHG emissions, beginning in 2027 (on prior fiscal year information). 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 former 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. On December 2, 2023, the EPA issued its final rule, which targets the reduction of emissions of methane and other air pollutants from oil and gas operations. Specifically, the rule establishes New Source Performance Standards to reduce emissions of methane and other volatile organic compounds from new and modified sources, including produced water storage tanks. The rule became effective May 7, 2024 and requires monitoring and repair of methane leaks and certain reporting requirements. On March 6, 2024, the Securities and Exchange Commission (“SEC”) adopted a new set of rules that require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant’s business, results of operations, or financial condition, Scope 1 and Scope 2 GHG emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the SEC ’s new climate rules, which have been consolidated and will be heard in the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC issued an order staying the final rules pending judicial review before ultimately voting to withdraw its defense of the rule on March 27, 2025. 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 19 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 and regulations relating to climate change, 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 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 the 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 (“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 the PHMSA’s safety authority and repeatedly extended it, most recently in the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020. 20 Railcar Regulation We transport a significant portion of our natural gas liquids via rail transportation, and we 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 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. In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. Although these expenditures cannot be accurately estimated at this time, 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 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, our common unit price, distributions on our preferred units and our ability to issue equity and incur debt. • Failure of our banking institutions. 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. 21 • Declining demand for hydrocarbons, commodity prices and production volumes, inability to acquire new pore space or loss of existing pore space, 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, 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 financial derivative contracts. • Reduced demand for our products due to energy efficiency, new technologies, alternative energy sources and new regulations. • Seasonal weather conditions, including warm winter weather and natural or man-made disasters. • Our ability to successfully complete, integrate and operate 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. 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 an Investment in Us • Our amended and restated limited partnership agreement (“Partnership Agreement”) limits the fiduciary duties of our GP to our unitholders and restricts the remedies available to our unitholders. • Conflicts of interest by our GP and its affiliates. • Our unitholders have limited voting rights. • Control of our GP or the IDRs (as defined herein) may be transferred to a third party. • Our GP 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 GP may elect to cause us to issue common units while also maintaining its GP 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. 22 • 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 actions that we may 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 common 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. 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. • Pandemics, terrorism and political unrest. • Product liability claims and litigation. • A failure in our operational systems or cybersecurity 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 GP and the payment of costs and expenses, including reimbursement of expenses to our GP. 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 and natural gas liquids 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; 23 • restrictions contained in the ABL Facility, Term Loan B and the indenture governing our 2029 Senior Secured Notes and 2032 Senior Secured Notes (collectively, the “Indenture”); • 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 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 GP; and • other business risks discussed in this Annual Report that may affect our cash levels. The board of directors of our GP expects to evaluate the reinstatement of the common unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, capital expenditures and the overall performance of our businesses. The quarterly common unit distributions were suspended with the quarter ended December 31, 2020. 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, 2025, the face amount of our long-term debt was $3.0 billion. Our level of indebtedness 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 the 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; • our flexibility in responding to changing business and economic conditions may be limited; and • it may make it more difficult for us to satisfy our debt obligations and increase the risk that we may default on our debt obligations. 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. Our leverage could have important consequences to our debt obligations. We will require substantial cash flow to meet our principal and interest obligations with respect to our debt obligations. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We may not have sufficient cash flow from operations and available borrowings under the ABL Facility to service our indebtedness. A significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable. 24 Restrictions in the ABL Facility, Term Loan B and Indenture could adversely affect our business, financial position, results of operations, and the value of our common units. The ABL Facility, Term Loan B and Indenture limit our ability to, among other things: • incur additional debt or issue letters of credit; • redeem or repurchase common 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, Term Loan B and Indenture may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and responding 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 2029 Senior Secured Notes, 2032 Senior Secured Notes, ABL Facility and Term Loan B. If the 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 Partnership may be required by Class D Preferred Unitholders to redeem all or a portion of the Class D Preferred Units, which could require a substantial amount of cash. At any time on or after July 2, 2027, each Class D Preferred Unitholder will have the right to require the Partnership to redeem on a date not prior to the 180th day after July 2, 2027 all or a portion of the Class D Preferred Units then held by such preferred unitholder for the then-applicable redemption price, which may be paid in cash or, at the Partnership’s election, a combination of cash and a number of common units not to exceed one-half of the aggregate then-applicable redemption price, as more fully described in our Partnership Agreement. Furthermore, upon a Class D Change of Control (as defined in our Partnership Agreement), each Class D Preferred Unitholder will have the right to require the Partnership to redeem the Class D Preferred Units then held by such Preferred Unitholder at a price per Class D Preferred Unit equal to the applicable redemption price. We cannot assure you that we will have sufficient cash flow, liquidity or the ability to incur indebtedness or sell assets on terms that are commercially reasonable in order to redeem the Class D Preferred Units, even if required to do so. In addition, we may seek to address the outstanding balances on the Class D Preferred Units prior to when they are required to be redeemed, which may impact our ability to service our indebtedness. Increasing interest rates could impact our financing costs, 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, Class C Preferred Units and Class D Preferred Units. The distribution rates on our Class B Preferred Units converted from fixed rates to floating rates on July 1, 2022, while the distribution rates on our Class C Preferred Units converted from fixed rates to floating rates on April 15, 2024 25 and Class D Preferred Units converted from fixed rates to floating rates on October 15, 2024. 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. Our cash and cash equivalents may be exposed to failure of our banking institutions. While we seek to minimize our exposure to third-party losses of our cash and cash equivalents, we hold our balances in several large banking institutions. Notwithstanding such allocation, we are subject to the risk of bank failure. For example, on March 10, 2023, Silicon Valley Bank (“SVB”) was unable to continue its operations and the Federal Deposit Insurance Corporation was appointed as receiver for SVB and created the National Bank of Santa Clara to hold the deposits of SVB. None of our cash and cash equivalents were held at SVB. However, if the banking institutions where we hold deposits were to experience a similar failure, we could experience additional risk. Any such loss or limitation on our cash and cash equivalents would adversely affect our business. Risks Related to the Operations of Our Business Our business depends on the availability of crude oil and natural gas liquids 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, which 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 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 26 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 segment 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 Water Solutions business depends upon available pore space in subsurface geologic formations by which we can dispose of produced water through underground injection wells. Our inability to acquire new pore space or our loss of existing pore space may negatively impact our ability to service new and existing customers. We dispose of produced water generated by our customers during oil and gas operations by drilling disposal wells and injecting such produced water into porous subsurface geologic formations. The amount of subsurface pore space that is capable of permanently storing injected produced water is finite and requires constant replenishment. As we continue to inject produced water into our existing produced water disposal wells, we may exhaust the geologic or technical limits of the subsurface strata for produced water injection. Furthermore, state regulatory bodies in Texas and New Mexico, which have permitting authority over disposal wells, have imposed new requirements in the permitting of produced water disposal wells to assess any relationship between induced seismicity and the use of such wells. State regulators may deny, modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity or would be operating at impermissible pressure levels. States have also issued, and may in the future issue, orders to temporarily shut down or to curtail the injection depth, injection capacity or injection rate of existing wells because of concerns over induced seismicity. Any loss of pore space or injection capacity for technical, geological or regulatory reasons could require us to spend significant time and capital expenditures to locate, apply for, permit, drill, complete and place into service new disposal wells and to build pipeline infrastructure to transport produced water to such new wells. Our customers’ oil and gas production growth plans may also require us to secure additional pore space and disposal wells and build new pipeline infrastructure. Permits for new disposal wells could be challenged for a variety of reasons by our competitors, oil and gas producers, landowners or non-governmental organizations. Such regulatory challenges could be successful and prevent us from being able to secure additional disposal capacity. New disposal wells may also subject us to higher royalty rates. Furthermore, we may not have contractual or real property rights to dispose of produced water at locations that are in geographic proximity to our customers’ existing or new oil and gas production wells or our existing injection wells and pipeline infrastructure. In such cases, we would be required to spend significant amounts of capital to build new pipeline infrastructure to transport produced water to distant disposal locations. If we are unable to accept all of the produced water delivered to us by our customers because we lack available pore space for underground injection, we could be subject to contractual penalties for alternative disposal solutions, including trucking, and such penalties could be significant. Any curtailment of our customers’ oil and gas production due to a lack of available pore space or injection capacity would result in lost revenue to us and could trigger contractual termination rights. Any of these events, either individually or in aggregate, could result in a material adverse effect on our business, financial condition or results of operations. 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 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 27 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. 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. 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 businesses. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues. Our business would be adversely affected if service at our principal storage facilities, 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 by railcar. We do not own or operate the railroads on which these railcars are transported. Any disruptions in the operations of these railroads would 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 most 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 and natural gas liquids. We own natural gas liquids and crude oil terminals and lease storage capacity from third-party natural gas liquids. 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 28 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 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 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 market 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 risk 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. 29 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. The Inflation Reduction Act of 2022 (“IRA”) could impact demand for hydrocarbon fuel products and impose new costs on certain customers. In August 2022, former President Biden signed the IRA, which contains, among other things, numerous incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration. In addition, the IRA imposes a federal fee on the emission of methane from sources required to report their GHG emissions to the EPA, including certain sources in the onshore petroleum and natural gas production categories. Some of our producer customers face exposure to the IRA pay to emit methane program. In addition, the multiple incentives offered for various clean energy industries referenced above could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business. 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 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. 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. 30 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, environmental justice communities, tribal groups, local groups and other advocates. Such opposition could take many forms, including the delay or denial of required governmental permits, 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. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. 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 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. Risks Related to Regulatory Compliance Our sales of crude oil, condensate, natural gas liquids 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. 31 The intrastate transportation or storage of crude oil 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 (“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, 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. 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, 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 and natural gas liquids. For instance, our Water Solutions segment 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 restriction 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 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 administered by the DOT. We also 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. 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, 32 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 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. 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 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, but most recently, in December 2023, the EPA finalized its rulemaking establishing New Source Performance Standards to reduce emissions of methane and other volatile organic compounds from new and modified sources. 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. The United States withdrew from the Paris Agreement on November 4, 2020, and although former President Biden signed executive orders on January 20, 2021 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, on January 20, 2025, President Trump issued an Executive Order for the United States to again withdraw from the Paris Agreement. Such withdrawal is expected to take effect in 2026. 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 33 as through the cessation of leasing public land for hydrocarbon development. For example, on January 27, 2021, former 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 (“DOI”) 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. While the DOI 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. The U.S. 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. 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 34 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 DOI acting pursuant to an Executive Order from former President Biden suspended the federal oil and gas leasing program indefinitely. Although the DOI announced the resumption of onshore oil and gas leasing in April 2022, the program is being significantly reformed, with 80 percent less land available for leasing from the acreage originally nominated. On April 12, 2024, the DOI finalized a comprehensive update to federal onshore oil and gas leasing regulations on Bureau of Land Management-managed public lands, which increased bonding requirements, royalty rates, and minimum bids. Actions such as these could have a material adverse effect on us and our industry. Restrictions on drilling and related activities intended to protect certain species of wildlife or their habitat may adversely affect our customers’ ability to conduct drilling and related activities in some of the areas where we operate. Various federal and state statutes prohibit certain actions that harm endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the MBTA, the BGEPA, the CWA, CERCLA and the Oil Pollution Act. The USFWS may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay, restrict or prohibit our customers’ land access or oil and gas development. If an adverse impact to species or damages to wetlands, habitat or natural resources occurs or may occur as a result of our or our customers’ activities, government entities or, at times, private parties may act to prevent such activities or seek damages for harm to species, habitat or natural resources resulting from our activities or our customers’ drilling, construction or releases of oil, wastes, hazardous substances or other regulated materials, which could reduce the demand for our services. For example, in May 2024, the dunes sagebrush lizard, which is found in areas where we operate, was listed as endangered under the ESA. In addition, the lesser prairie-chicken, which can also be found in areas where we operate, was listed under the ESA effective March 27, 2023. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our assets and operations are located, operations in those areas could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. 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, including various state regulatory bodies, 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. In January 2024, the Texas Railroad Commission indefinitely suspended all deep oil and gas produced water injection in Culberson and Reeves counties, which directly impacted one of our disposal wells. While this suspension resulted in a loss of 10,000 barrels per day of disposal capacity, the suspension did not materially impact our water disposal business. 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. To date, due to the capacity of our integrated system in the affected areas, the diverse locations of our disposal facilities, and the connectivity of our system, our ability to dispose of produced water has not been materially impacted by these actions, and with our unique positioning outside of the affected areas, we have the ability to grow our asset base. 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 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 35 FERC to establish a simplified and generally applicable ratemaking methodology for oil pipelines, keeping with its statutory mandate to ensure that oil pipelines’ rates are just and reasonable. Intrastate transportation and gathering pipelines that do not provide interstate services are subject to regulation by state regulatory commissions, such as the Texas Railroad Commission. 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 an Investment in Us Our Partnership Agreement limits the fiduciary duties of our GP to our unitholders and restricts the remedies available to our unitholders for actions taken by our GP that might otherwise be breaches of fiduciary duty. Fiduciary duties owed to our unitholders by our GP 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 GP would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement: • limits the liability and reduces the fiduciary duties of our GP, 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 36 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; • permits our GP to make a number of decisions in its individual capacity, as opposed to in its capacity as our GP. This entitles our GP 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 GP shall not have any liability to us or our unitholders for decisions made in its capacity as GP so long as it acted in good faith, meaning our GP 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 GP 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 GP 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 GP 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 GP 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 GP 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 GP and its 0.1% GP interest in us. Although our GP has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our GP have a fiduciary duty to manage our GP in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our GP are executive officers or directors of affiliates of our GP, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our GP, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our GP 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 GP to our unitholders and restricts the remedies available to our unitholders for actions taken by our GP 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 GP 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 GP to pursue a business strategy that favors us; • except in limited circumstances, our GP has the power and authority to conduct our business without unitholder approval; • our GP 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 GP 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 GP; • our GP determines which costs incurred by it are reimbursable by us; • our GP 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; 37 • 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. This cash may be used to fund distributions to our GP in respect of the GP interest or the incentive distribution rights (“IDRs”); • our Partnership Agreement does not restrict our GP 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 GP intends to limit its liability regarding our contractual and other obligations; • our GP 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 GP controls the enforcement of the obligations that it and its affiliates owe to us; • our GP decides whether to retain separate counsel, accountants or others to perform services for us; and • our GP may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our GP’s IDRs without the approval of the conflicts committee of the board of directors of our GP 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 GP will be restricted from engaging in any business activities other than acting as our GP 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 GP 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 GP 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 GP 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 GP or its board of directors. The board of directors of our GP 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 GP, they will have limited ability to remove our GP. 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 GP, its affiliates, their direct transferees and their indirect transferees approved by our GP (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our GP, cannot vote on any matter. Our GP interest or the control of our GP may be transferred to a third party without the consent of our unitholders. Our GP may transfer its GP 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 GP to a third party. The new 38 owner of our GP would then be in a position to replace the board of directors and officers of our GP with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. The IDRs of our GP may be transferred to a third party. Our GP may transfer its IDRs to a third party at any time without the consent of our unitholders. If our GP transfers its IDRs to a third party but retains its GP interest, our GP 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 GP 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 GP and its affiliates own more than 80% of the common units, our GP 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. Our GP, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its GP 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 GP 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 GP, 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. 39 If our GP 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 GP 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 GP on the IDRs in the prior two quarters. We anticipate that our GP 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 GP 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 GP interests to our GP 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 GP, 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 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 2,125,000 common units at exercise prices ranging from $13.56 per unit to $16.28 per unit. Any exercise of these warrants would cause dilution to existing common unitholders 40 and may place downward pressure on the trading price of our common units. All outstanding warrants are currently exercisable and any unexercised warrants will expire on the tenth anniversary of the date of issuance. The warrants will not participate in cash distributions. For additional information related to the warrants, see Note 9 to our consolidated financial statements included in this Annual Report. 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 (“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 Tax Cuts and Jobs Act of 2017 (“Act”)), 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 Act signed into law by President Trump 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. 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 41 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 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 GP 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 GP 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. 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 federal income tax purposes, our unitholders will be treated as partners to whom we will allocate taxable income that could be different than the cash we distribute, therefore, 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 42 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 a 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 a 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 are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to a non-United States unitholder will be subject to withholding taxes at the highest applicable effective tax rate and a non-United States unitholder who sells or otherwise disposes of a common unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that common unit. Non-United States persons will be required to file federal income tax returns and pay tax on their share of our taxable income. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non- United States unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-United States unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%. For a transfer of interests in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. We are required to issue qualified notices regarding these matters. Our qualified notices can be found on our website. 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. 43 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 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 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 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 common 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 common 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 common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 common units. We have adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our GP 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 GP. 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 GP, 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 44 tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the GP 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. 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, certain 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. Further, while unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of qualified publicly traded partnership income, this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025. A holder of Preferred Units will be required to recognize a 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 45 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 a 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 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 46 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 (“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. 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 of the Sarbanes-Oxley Act. 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 impact of a global public health crisis may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties. Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we purchase and sell and the level of services that we provide to customers, which in turn impacts our financial position, results of operations and cash flows. The global and U.S. economy has generally recovered from the negative economic impacts of the COVID-19 pandemic, which disrupted global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial and commodity markets. While the World Health Organization declared an end to the global public health emergency for COVID-19 in May 2023, a future global public health crisis could lead to similar disruptions and related economic repercussions. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for hydrocarbons that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities. The potential impact of these types of events on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of and response to a public health crisis, the related impact on overall economic activity and the potential long-term impacts on demand for crude oil and other products, all of which cannot be predicted with certainty. 47 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. Terrorist attacks in the areas of our operations could negatively impact our ability to transport crude oil and natural gas liquids 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 or other litigation matter 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 or other litigation matters could materially and adversely affect our business, consolidated results of operations, financial position and cash flows. A failure in our operational systems or cybersecurity 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 cybersecurity attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cybersecurity attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt 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 1C. Cybersecurity Cybersecurity Governance and Strategy Our cybersecurity program is designed to provide logical and physical security protection of our infrastructure, systems and data from theft and destruction that could impact our operations, reputation, and regulatory compliance. To safeguard us from a cyber event, specific mitigating cybersecurity controls, systems and incident procedures exist based upon the United States Department of Commerce National Institute of Standards and Framework (“NIST”) Cybersecurity Framework, which is an industry recognized security framework for private and public sectors. Our commitment to cybersecurity is reflected in our extensive program and related technology investments for continual cybersecurity posture enhancements. 48 Our cybersecurity governance and strategy program to prevent, detect, manage, mitigate, and remediate cyber threats is comprised of: • Controls based upon the NIST Cybersecurity Framework for enterprise governance, critical asset management, internal and third-party risk management , segregated access control management, data security and protection, anomaly logging and general security monitoring, incident response, security training and awareness, and disaster recovery testing. • Security Policies and Procedures for cybersecurity, incident response, acceptable use, change control, disaster recovery, backup and recovery, business continuity, business operations recovery, third-party vendor security assessments , vulnerability and patch management, data privacy, and various regulatory compliance areas. • Enterprise Risk Management to identify, assess and mitigate internal and third-party risks in a continuous life cycle program which is also based on the NIST Cybersecurity Framework. This risk management framework incorporates corporate and business segment SCADA (Supervisory Control and Data Acquisition) system risks for an integrated enterprise approach. • Various Cybersecurity Systems and Protocols for aggregated monitoring and behavior analytics, detection and response, network protection and segmentation, layered security methods for defense-in-depth, vulnerability and patch management, backup and recovery, and asset management. • Employee Education for continual security awareness and threat diligence. The program includes a myriad of monthly and quarterly required cyber training for high-risk areas plus mandatory semi-annual training for all employees and third parties with access to our network. Additionally, monthly simulated phishing campaigns and newsletters reinforce cyber risks and general security awareness. Cybersecurity Risk and Threat Management Our Enterprise Cybersecurity Risk Management program is a continuous life cycle approach with a formal annual risk assessment followed by internal and third-party risk assessments throughout the year. Annually, an independent security expert vendor is engaged to conduct a cybersecurity risk assessment based upon industry and technology standards. The assessment results are prioritized then tracked within our Governance, Risk and Control system which derives the specific risk likelihood and impact mitigated risk score. Cybersecurity projects, controls and practices are then developed to mitigate the identified risks. Monthly, the Compliance and Security Steering Committee meets to review risk register, current threat assessments and related mitigation efforts for risk management tracking. Additionally, on a quarterly basis, our Chief Information Officer (“CIO”) presents the risk score and mitigation updates to the board of directors of our GP for risk oversight. Event management of a cyber incident follows our Cybersecurity Policy Incident Response Procedure (“Incident Response Policy”) which is based upon the NIST framework. The procedure includes incident identification, isolation and containment, investigation, impact analysis, communication, materiality assessment including in aggregate with previous events, and reporting steps and associated ownership. Annually, the Incident Response Policy is tested with the key owners to validate the procedure and for training purposes. Impact of Risks from Cybersecurity Threats While we have not, as of the date of this Annual Report, experienced a cybersecurity threat or incident that resulted in a material adverse impact to our business or operations, there can be no guarantee that we will not experience such an incident in the future due to the increasing global cyberattack volume, frequency, and sophistication. Such incidents, whether or not successful, could result in us incurring significant costs related to, for example, implementing additional threat protection measures, providing modifications or replacements to our products and services, defending against litigation, responding to regulatory inquiries or actions, providing customers with incentives to maintain a business relationship with us, or taking other remedial steps with respect to third parties , as well as incurring reputational harm. In addition, these threats are constantly evolving, thereby increasing the difficulty of successfully defending against them or implementing adequate preventive measures even with our various cybersecurity protection and resilience protocols. Management’s Cyber Expertise Our cybersecurity program is led by our CIO who is also our Chief Information Security Officer. Our CIO has been with us since 2014 and has over 30 years of information technology and compliance experience. Our CIO has a Bachelor of Science in Management Information Systems and holds the Certified Information Systems Audit security certification as well. Our security members are comprised of various industry technology skilled resources in cybersecurity, business continuity and 49 system recovery, event management, system administration, network engineering, and regulatory compliance with a collective 100 plus years of experience. Security operations partners are also leveraged for 24x7x365 managed detection and response support plus provide expert cybersecurity resources as an extension of our team. Board of Director’s Cyber Oversight For cybersecurity oversight, the board of directors of our GP training program is designed to inform members of the current cyber threat tactics and provide relevant, periodic educational security technology information. The cybersecurity training program includes: • An annual presentation overview of our cyber controls and related systems for a comprehensive understanding of our cybersecurity protection and resilience; • Quarterly cybersecurity training on topics such as ransomware, phishing, impersonation, social engineering, third-party security risks , business email compromise, and artificial intelligence to reinforce general security knowledge; and • Monthly cybersecurity newsletter distribution for current threat tactics and general security awareness. Additionally, the CIO presents a quarterly cyber update to the board of directors of our GP for an overview of cyber program key metrics and trends, cyber event executive summaries (based upon occurrence), fiscal year security goals and tracking progression, risk register scoring, and status updates on cyber related projects. 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, 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, Term Loan B and Indenture 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 caption “ Legal Contingencies ” in Note 8 to our consolidated financial statements included in this Annual Report, which is incorporated by reference into this Item 3. Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will exceed a specified threshold. Pursuant to SEC regulations, we use a threshold of $1 million for such proceedings. We believe that such threshold is reasonably designed to result in disclosure of environmental proceedings that are material to our business or financial condition. Applying this threshold, there are no environmental matters to disclose for the three years ended March 31, 2025. Item 4. Mine Safety Disclosures Not applicable. 50 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 May 27, 2025, there were approximately 70 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 GP, 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 GP for any one or more of the next four quarters. General Partner Interest Our GP is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% GP interest. Our GP’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 GP does not contribute a proportionate amount of capital to us to maintain its 0.1% GP interest. As of March 31, 2025, we owned 8.69% of our GP. Incentive Distribution Rights The GP will also receive, in addition to distributions on its 0.1% GP interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.” Our GP currently holds the IDRs, but may transfer these rights separately from its GP interest. The following table illustrates the percentage allocations of available cash from operating surplus between our limited partner unitholders and our GP based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our GP 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 GP 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 GP include its 0.1% GP interest, and assume that our GP has contributed any additional capital necessary to maintain its 0.1% GP 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 GP may receive on common units that it owns. 51 Restrictions on the Payment of Distributions As described in Note 7 to our consolidated financial statements included in this Annual Report, the ABL Facility, Term Loan B and Indenture contain covenants limiting our ability to pay distributions if we are in default under these agreements. Also, the Term Loan B and Indenture restrict us from paying distributions if our total leverage ratio (as defined within the Indenture and Term Loan B agreement) for the most recently ended four full fiscal quarters at the time of the distribution is greater than 4.75 to 1.00, while the ABL Facility restricts the payment of distributions if certain payment conditions (as defined in the ABL Facility) are below certain thresholds. 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. Securities Authorized for Issuance Under Equity Compensation Plan In connection with the completion of our initial public offering, our GP 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 NGL Energy Partners LP, a Delaware master limited partnership (“we,” “us,” “our,” or the “Partnership”), is a diversified midstream energy partnership that transports, treats, recycles and disposes of produced and flowback 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. NGL Energy Holdings LLC serves as our general partner (“GP”). At March 31, 2025, our operations included three segments as discussed below. Sale of Refined Products Business and Exiting Biodiesel Business As of March 31, 2025, we completed winding down our biodiesel business (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). On March 17, 2025, we signed a purchase and sale agreement to sell our refined products business, including certain working capital items, to a third-party (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). This sale closed on April 30, 2025. The sale of our refined products business and winding down of our biodiesel business represent a strategic shift in our operations and will have a significant effect on our operations and financial results going forward. Accordingly, the results of operations and cash flows for our refined products and biodiesel businesses within our Liquids Logistics segment have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted in the consolidated statements of operations and consolidated statements of cash flows (see Note 18 to our consolidated financial statements included in this Annual Report for a further discussion). Sale of Certain Natural Gas Liquids Terminals and Most of Our Wholesale Propane Business On February 5, 2025, we signed a purchase and sale agreement to sell 17 of our natural gas liquids terminals, most of our wholesale propane business, our interest in an unconsolidated entity and working capital to a third-party (see Note 1 to our consolidated financial statements included in this Annual Report for a further discussion). This sale closed on April 30, 2025. As this sale transaction did not represent a strategic shift that will have a major effect on our operations or financial results, operations related to this portion of our Liquids Logistics segment have not been classified as discontinued operations. 52 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 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 Denver-Julesburg (“DJ”) Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 958.3 million barrels of produced water across its areas of operation during the year ended March 31, 2025, 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 segment is driven in large part by the level of crude oil production in the areas where our facilities are located. Recently, our disposal volumes have been positively impacted by the increase in the level of crude oil production, particularly in the Delaware and Eagle Ford Basins, due to stable crude oil prices. 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 $311.5 million during the year ended March 31, 2025, compared to operating income of $231.3 million during the year ended March 31, 2024. 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 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 with acreage dedications and which include minimum volume commitments on our storage tanks and 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 2025 $ 66.75 $ 86.91 $ 71.48 2024 $ 67.12 $ 93.68 $ 83.17 2023 $ 66.74 $ 122.11 $ 75.67 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results. Our Crude Oil Logistics segment generated operating income of $46.1 million during the year ended March 31, 2025, compared to operating income of $52.1 million during the year ended March 31, 2024. 53 Liquids Logistics Our Liquids Logistics segment conducts supply operations for natural gas liquids to commercial, retail and industrial customers across the United States and Canada. These operations are conducted through our five owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars (updated for the transactions discussed above). We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia and we also own a propane pipeline in Michigan. 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. 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 2025 $ 0.61 $ 0.99 $ 0.83 $ 0.49 $ 1.01 $ 0.90 2024 $ 0.49 $ 0.91 $ 0.78 $ 0.53 $ 0.97 $ 0.84 2023 $ 0.63 $ 1.34 $ 0.74 $ 0.64 $ 1.39 $ 0.78 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 2025 $ 0.79 $ 1.26 $ 0.95 2024 $ 0.58 $ 1.14 $ 0.98 2023 $ 0.85 $ 1.65 $ 0.92 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 operating income of $14.1 million during the year ended March 31, 2025, compared to an operating loss of $13.2 million during the year ended March 31, 2024. 54 Consolidated Results of Operations The following table summarizes our consolidated statements of operations for the periods indicated: Year Ended March 31, 2025 2024 2023 (in thousands) Revenues $ 3,469,186 $ 4,153,307 $ 5,679,020 Cost of sales 2,507,077 3,185,434 4,689,414 Operating expenses 297,686 299,605 304,589 General and administrative expense 55,593 121,625 71,483 Depreciation and amortization 254,732 266,114 273,108 Loss on disposal or impairment of assets, net 31,448 115,936 86,776 Revaluation of liabilities (6,705) 2,680 9,665 Operating income 329,355 161,913 243,985 Equity in earnings of unconsolidated entities 6,565 4,120 4,120 Interest expense (280,078) (269,804) (275,438) (Loss) gain on early extinguishment of liabilities, net — (55,281) 6,177 Other income, net 4,262 2,782 30,410 Income (loss) from continuing operations before income taxes 60,104 (156,270) 9,254 Income tax benefit (expense) 4,885 (1,458) (219) Income (loss) from continuing operations 64,989 (157,728) 9,035 (Loss) income from discontinued operations, net of tax (21,826) 14,604 43,457 Net income (loss) 43,163 (143,124) 52,492 Less: Net income from continuing operations attributable to nonredeemable noncontrolling interests (3,749) (631) (1,106) Less: Net income from continuing operations attributable to redeemable noncontrolling interests (46) — — Net income (loss) attributable to NGL Energy Partners LP $ 39,368 $ (143,755) $ 51,386 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 commodity price volatility, demand fluctuations, acquisitions, dispositions and other transactions. Recent Developments Dispositions Disposition transactions impact the comparability of our results of operations between our current and prior fiscal years. See Note 1 and Note 17 to our consolidated financial statements included in this Annual Report for a discussion of dispositions that occurred during the current and prior fiscal years. Other Developments Seismic Activity The subsurface injection of produced water for disposal has been associated with induced seismic events in Texas and New Mexico. While these events have been of 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 the affected areas, the diverse locations of our disposal facilities, and the connectivity of our system, our ability to dispose of produced water has not been materially impacted by these actions, and with our unique positioning outside of the affected areas, we have the ability to grow our asset base. 55 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 borrow under our asset-based revolving credit facility (“ABL 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–General”). Subsequent Events See Note 20 to our consolidated financial statements included in this Annual Report for a discussion of transactions that occurred subsequent to March 31, 2025. Segment Operating Results for the Years Ended March 31, 2025 and 2024 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated. Year Ended March 31, 2025 2024 Change (in thousands, except per barrel and per day amounts) Revenues: Water disposal service fees $ 599,870 $ 572,972 $ 26,898 Sale of recovered crude oil 109,008 107,367 1,641 Recycled water 7,544 9,785 (2,241) Other revenues 39,265 40,694 (1,429) Total revenues 755,687 730,818 24,869 Expenses: Cost of sales-excluding impact of derivatives 7,848 10,146 (2,298) Derivative (gain) loss (5,001) 1,148 (6,149) Operating expenses 214,928 212,052 2,876 General and administrative expenses 6,120 5,417 703 Depreciation and amortization expense 217,227 214,480 2,747 Loss on disposal or impairment of assets, net 9,813 53,639 (43,826) Revaluation of liabilities (6,705) 2,680 (9,385) Total expenses 444,230 499,562 (55,332) Segment operating income $ 311,457 $ 231,256 $ 80,201 Produced water processed (barrels per day) Delaware Basin 2,303,142 2,123,337 179,805 Eagle Ford Basin 175,251 142,374 32,877 DJ Basin 146,956 150,426 (3,470) Other Basins — 740 (740) Total 2,625,349 2,416,877 208,472 Recycled water (barrels per day) 116,058 84,212 31,846 Total (barrels per day) 2,741,407 2,501,089 240,318 Skim oil sold (barrels per day) (1) 4,268 3,992 276 Service fees for produced water processed ($/barrel) (2)(3) $ 0.63 $ 0.65 $ (0.02) Recovered crude oil for produced water processed ($/barrel) (2) $ 0.11 $ 0.12 $ (0.01) Operating expenses for produced water processed ($/barrel) (2) $ 0.22 $ 0.24 $ (0.02) (1) As of March 31, 2023, approximately 34,380 barrels of skim oil were stored and were sold during the year ended March 31, 2024. (2) Total produced water barrels processed during the years ended March 31, 2025 and 2024 were 958,252,275 and 884,576,981, respectively. These amounts do not include 49,861,950 barrels and 63,968,944 barrels for the years ended March 31, 2025 and 2024, respectively, related to payments made by certain producers for committed volumes not delivered, as discussed further below. In addition, water pipeline revenue, which is included in Other Revenues, includes payments from a producer for 19,257,873 committed barrels not delivered during the year ended March 31, 2025. 56 (3) Excluding payments made by certain producers for committed volumes not delivered and the one-time item discussed below, service fees for produced water processed ($/barrel) would have been $0.60/barrel and $0.61/barrel during the years ended March 31, 2025 and 2024, respectively. Water Disposal Service Fee Revenues. The increase was due primarily to an increase in produced water volumes processed from contracted customers and higher fees charged for interruptible spot volumes. These increases were partially offset by the expiration of certain higher fee per barrel contracts which were replaced with lower fee per barrel contracts with an extended term and higher volumes received under contracts with lower fees per barrel. There was also a decrease in payments made by certain producers for committed volumes not delivered. In addition, during July 2023, we entered into a transaction in which a portion of the total consideration received was allocated to revenue due to the termination of a minimum volume water disposal contract (see Note 17 to our consolidated financial statements included in this Annual Report). Recovered Crude Oil Revenues. The increase was due primarily to an increase in skim oil barrels sold due to more skim oil recovered from receiving more water in higher oil cut basins, partially offset by lower realized crude oil prices received from the sale of skim oil barrels. Also, during the year ended March 31, 2024, we sold approximately 34,380 barrels of skim oil that were stored as of March 31, 2023 due to tighter pipeline specifications. Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities. The decrease was due primarily to lower pricing for recycled water, partially offset by higher recycled water volumes related to timing of water to be used in completions. Other Revenues. Other revenues primarily include reimbursements from construction projects, booster operating fees and generator rentals, water pipeline revenues, solids disposal revenues, land surface use revenues and brackish non-potable water revenues. The decrease was due primarily to lower land surface use revenues, mining revenues and lease revenue from certain surface use and compensation agreements primarily due to the sale of our ranches in April 2024 (see Note 17 to our consolidated financial statements included in this Annual Report). We also had lower reimbursements from construction projects, booster operating fees and generator rentals. These decreases were partially offset by higher water pipeline revenue, including payments from a producer for committed volumes not delivered, due to our expanded Lea County Express Pipeline system (“LEX II”) commencing operations during the three months ended December 31, 2024. Cost of Sales-Excluding Impact of Derivatives . The decrease was due primarily to lower recycling costs and a decrease in disposal fees paid to third-parties, partially offset by costs incurred that will be reimbursed by producers for generator and fuel costs at various booster stations. Derivative (Gain) 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, 2025, we had $5.0 million of net unrealized losses on derivatives and $10.0 million of net realized gains on derivatives. During the year ended March 31, 2024, we had $0.4 million of net unrealized losses on derivatives and $0.8 million of net realized losses on derivatives. Operating and General and Administrative Expenses . The increase was due primarily to higher royalty expense due to volumes related to the LEX II pipeline commencing operations and increased volumes at certain other saltwater disposal wells, higher business insurance expense for remediation costs incurred and lower severance taxes in the prior year as a result of a severance tax refund in September 2023 related to prior periods. These increases were partially offset by lower chemical expense due to purchasing fewer chemicals and using them more efficiently and lower repairs and maintenance expense due to the timing of repairs and tank cleaning. Depreciation and Amortization Expense . The increase was due primarily to depreciation of newly developed facilities and infrastructure, partially offset by certain long-term assets being fully amortized, impaired or sold during the fiscal years ended March 31, 2024 and 2025. Loss on Disposal or Impairment of Assets, Net . During the year ended March 31, 2025, we recorded a net loss of $15.1 million primarily related to the write down of the value of certain saltwater disposal wells and other assets as well as abandonment of certain capital projects and the retirement of certain other assets. We also recorded a loss of $8.0 million related to the write down of certain investments in unconsolidated entities and related assets to fair value less cost to sell (see Note 18 to our consolidated financial statements included in this Annual Report). In addition, we recorded a $3.4 million loss from the settlement of a dispute related to a force majeure event, which resulted in the plugging and abandoning of a disposal well in a prior period. Lastly, we recorded a net gain of $10.1 million primarily related to the sale of certain assets (see Note 17 to our consolidated financial statements included in this Annual Report) and a gain of $6.5 million from insurance recoveries 57 for certain saltwater disposal facilities and boosters damaged in a prior period. During the year ended March 31, 2024, we recorded a net loss of $37.5 million primarily related to the write down of the value of certain saltwater disposal wells as well as the abandonment of certain capital projects and the retirement of certain assets, a net loss of $17.6 million primarily related to the sale of certain assets and an impairment of $2.4 million for certain leases due to underutilization of certain freshwater wells. In addition, we recorded a gain of $3.9 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period. Revaluation of Liabilities. During the year ended March 31, 2025, 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 produced water volumes from our customers, resulting in a decrease to the expected future royalty payment. During the year ended March 31, 2024, 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, 2025 2024 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 806,653 $ 1,597,238 $ (790,585) Crude oil transportation and other sales 73,249 59,373 13,876 Total revenues 879,902 1,656,611 (776,709) Expenses: Cost of sales-excluding impact of derivatives 771,526 1,514,370 (742,844) Derivative (gain) loss (2,872) 7,367 (10,239) Operating expenses 38,408 39,004 (596) General and administrative expenses 2,673 3,780 (1,107) Depreciation and amortization expense 25,070 36,922 (11,852) (Gain) loss on disposal or impairment of assets, net (1,004) 3,094 (4,098) Total expenses 833,801 1,604,537 (770,736) Segment operating income $ 46,101 $ 52,074 $ (5,973) Crude oil sold (barrels) 10,412 20,068 (9,656) Crude oil transported on owned pipelines (barrels) 22,238 25,611 (3,373) Crude oil storage capacity - owned and leased (barrels) (1) 5,232 5,232 — Crude oil storage capacity leased to third-parties (barrels) (1) 1,650 2,250 (600) Crude oil inventory (barrels) (1) 339 573 (234) Crude oil sold ($/barrel) $ 77.473 $ 79.591 $ (2.118) Cost per crude oil sold ($/barrel) (2) $ 74.100 $ 75.462 $ (1.362) Crude oil product margin ($/barrel) (2) $ 3.373 $ 4.129 $ (0.756) (1) Information is presented as of March 31, 2025 and March 31, 2024, respectively. (2) Cost and product margin per barrel excludes the impact of derivatives. Crude Oil Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to lower sales volumes due to lower production on acreage dedicated to us in the DJ Basin during the year ended March 31, 2025, compared to the year ended March 31, 2024. Lower crude oil prices also contributed to the decrease. During the year ended March 31, 2025, the crude oil product margin decreased primarily due to lower volumes as discussed further above. Contributing to the decrease in product margin and margin per barrel was the expiration of certain higher-margin purchase contracts during the year ended March 31, 2024, which resulted in lower margin realized on barrels purchased during the year ended March 31, 2025. The decrease in margin per barrel for the year ended March 31, 2025, compared to the year ended March 31, 2024 was partially offset by higher price and quality differentials realized, and the sale 58 of the remaining pipeline transportation deficiency credits included in gross margin during the year ended March 31, 2025. Crude oil product margin calculations do not include gains and losses from derivatives that may offset the movement in the physical margin. Derivative (Gain) Loss. Our cost of sales during the year ended March 31, 2025 included $1.1 million of net realized losses on derivatives and $4.0 million of net unrealized gains on derivatives. Our cost of sales during the year ended March 31, 2024 included $58.4 million of net realized gains on derivatives and $65.8 million of net unrealized losses on derivatives. The amounts in the previous sentence for the year ended March 31, 2024 includes net realized gains of $60.9 million and net unrealized losses of $61.4 million associated with derivative instruments related to our hedge of the CMA Differential Roll, defined and discussed below under “–Non-GAAP Financial Measures.” Crude Oil Transportation and Other Sales. The increase was primarily due to higher tariff revenue on the Grand Mesa Pipeline as a result of signing a new shipper during the open season that ended January 5, 2024. Additionally, the year ended March 31, 2025 benefited from higher terminaling revenue from an acreage dedication in the Eagle Ford Basin and higher throughput revenue from crude oil transported on third-party pipelines. These increases were partially offset by lower storage fees at our Cushing terminal during the year ended March 31, 2025. During the year ended March 31, 2025, physical volumes on the Grand Mesa Pipeline averaged approximately 61,000 barrels per day, compared to approximately 70,000 barrels per day for the year ended March 31, 2024. Lower contracted volumes were shipped on the Grand Mesa Pipeline due to lower production on acreage dedicated to us in the DJ Basin. Operating and General and Administrative Expenses . The decrease was primarily due to lower utilities expense and lower materials and supplies expense on the Grand Mesa Pipeline and at our Cushing terminal from lower volumes flowing through the system during the year ended March 31, 2025, compared to the year ended March 31, 2024. In addition, the year ended March 31, 2025 benefited from lower cleaning, repairs and maintenance costs on our owned railcars, lower environmental costs at one of our terminals, and lower corporate cost allocations. These decreases were partially offset by higher incentive compensation expenses and higher ad valorem taxes assessed on the Grand Mesa Pipeline by the State of Colorado. Depreciation and Amortization Expense. The decrease was primarily due to certain assets becoming fully depreciated during the year ended March 31, 2024. (Gain) Loss on Disposal or Impairment of Assets, Net . During the year ended March 31, 2025, we recorded a net gain of $1.0 million primarily due to the gain on the sale of railcars (see Note 17 to our consolidated financial statements included in this Annual Report), partially offset by the write-down in value of linefill expected to be sold over the next four months and the loss on the sale of certain other assets. During the year ended March 31, 2024, we recorded a net loss of $3.1 million primarily due to the retirement or sale of certain assets. 59 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated. As discussed above, the operating results of our refined products and biodiesel businesses have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted. Year Ended March 31, 2025 2024 Change (in thousands, except per gallon amounts) Propane: Sales $ 755,646 $ 739,591 $ 16,055 Cost of sales-excluding impact of derivatives 721,372 692,649 28,723 Derivative (gain) loss (1,509) 2,463 (3,972) Product margin 35,783 44,479 (8,696) Butane: Sales 649,452 628,685 20,767 Cost of sales-excluding impact of derivatives 606,694 587,307 19,387 Derivative loss 14,136 2,771 11,365 Product margin 28,622 38,607 (9,985) Other products: Sales-excluding impact of derivatives 414,985 383,998 30,987 Cost of sales-excluding impact of derivatives 393,935 367,293 26,642 Derivative (gain) loss (272) 25 (297) Product margin 21,322 16,680 4,642 Service: Sales 13,529 14,151 (622) Cost of sales 1,636 1,379 257 Product margin 11,893 12,772 (879) Expenses: Operating expenses 44,350 48,549 (4,199) General and administrative expenses 7,208 7,281 (73) Depreciation and amortization expense 9,408 9,963 (555) Loss on disposal or impairment of assets, net 22,596 59,923 (37,327) Total expenses 83,562 125,716 (42,154) Segment operating income (loss) $ 14,058 $ (13,178) $ 27,236 Natural gas liquids storage capacity - owned and leased (gallons) (1) 52,721 122,831 (70,110) Propane sold (gallons) 760,287 811,035 (50,748) Propane sold ($/gallon) $ 0.994 $ 0.912 $ 0.082 Cost per propane sold ($/gallon) (2) $ 0.949 $ 0.854 $ 0.095 Propane product margin ($/gallon) (2) $ 0.045 $ 0.058 $ (0.013) Propane inventory (gallons) (1) 11,833 35,177 (23,344) Butane sold (gallons) 516,202 537,015 (20,813) Butane sold ($/gallon) $ 1.258 $ 1.171 $ 0.087 Cost per butane sold ($/gallon) (2) $ 1.175 $ 1.094 $ 0.081 Butane product margin (loss) ($/gallon) (2) $ 0.083 $ 0.077 $ 0.006 Butane inventory (gallons) (1) 21,871 17,790 4,081 Other products sold (gallons) 277,495 263,422 14,073 Other products sold ($/gallon) $ 1.495 $ 1.458 $ 0.037 Cost per other products sold ($/gallon) (2) $ 1.420 $ 1.394 $ 0.026 Other products product margin ($/gallon) (2) $ 0.075 $ 0.064 $ 0.011 Other products inventory (gallons) (1) 8,556 5,623 2,933 (1) Information is presented as of March 31, 2025 and March 31, 2024, respectively. 60 (2) Cost and product margin (loss) per gallon excludes the impact of derivatives. Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, were primarily due to higher prices during the quarter ended March 31, 2025 due to the cold weather experienced throughout the United States during the first two months of the quarter. Propane volumes decreased during the year ended March 31, 2025 due to lower contracted volumes and reduced retail customer demand. Propane product margins, excluding the impact of derivatives, decreased during the year ended March 31, 2025 primarily due to lower volumes. For most of the year ended March 31, 2025, we sold higher priced inventory into a market of declining prices, compared to the year ended March 31, 2024, when we were selling lower priced inventory into a market with rising prices. In addition, during the quarter ended March 31, 2025, due to an increase in demand due to the colder than normal weather, we were short product and had to purchase spot barrels at higher prices to fulfill term obligations, resulting in lower margins. Propane Derivative (Gain) Loss. Our cost of propane sales included $3.0 million of net unrealized losses on derivatives and $4.5 million of net realized gains on derivatives during the year ended March 31, 2025. During the year ended March 31, 2024, our cost of propane sales included $4.6 million of net unrealized gains on derivatives and $7.0 million of net realized losses on derivatives. Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, were due primarily to higher butane prices during the year ended March 31, 2025. Butane product margins, excluding the impact of derivatives, increased during the year ended March 31, 2025, as compared to the year ended March 31, 2024, primarily due to higher prices, partially offset by lower volumes due to a weak gasoline blending season. Butane Derivative Loss. Our cost of butane sales during the year ended March 31, 2025 included $0.6 million of net unrealized gains on derivatives and $14.7 million of net realized losses on derivatives. Our cost of butane sales included $3.2 million of net unrealized losses on derivatives and $0.5 million of net realized gains on derivatives during the year ended March 31, 2024. Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, were primarily due to an increase in prices and volumes. Strong spot markets led to an increase in isobutane and natural gasoline sales and asphalt sales increased due to a consistent supply during the year ended March 31, 2025. Other products sales product margins, excluding the impact of derivatives, increased during the year ended March 31, 2025 due to the increase in volumes and prices, as discussed further above. Other Products Derivative (Gain) Loss. Our derivatives of other products included $0.3 million of net realized gains on derivatives during the year ended March 31, 2025. Our derivatives of other products during the year ended March 31, 2024 included $0.1 million of net realized gains on derivatives and $0.1 million of net unrealized losses on derivatives. Service Sales and Cost of Sales. The sales include storage, terminaling and transportation services income. Sales and cost of sales during the year ended March 31, 2025 remained consistent with the year ended March 31, 2024. Operating and General and Administrative Expenses. The decrease during the year ended March 31, 2025 compared to the year ended March 31, 2024 was primarily due to a decrease in incentive compensation due to lower than expected earnings, a decrease in travel and entertainment expenses due to our efforts in the prior year to visit all customers and lower office lease expense due to the sale of certain terminals in the prior year. Depreciation and Amortization Expense. The decrease was due to a customer relationship intangible asset being fully amortized as of June 30, 2023. Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2025, we recorded a net loss of $22.6 million. The net loss was due to a goodwill impairment loss of $17.9 million in our Wholesale/Terminal reporting unit (see Note 5 to our consolidated financial statements included in this Annual Report). We also recorded a net loss of $7.3 million due to costs incurred related to the sale of certain natural gas liquid terminals and a net gain of $2.0 million for the sale of the Green Bay terminal discussed in Note 17 to our consolidated financial statements included in this Annual Report. During the year 61 ended March 31, 2024, we recorded a goodwill impairment loss of $69.2 million in our Wholesale/Terminal reporting unit (see Note 5 to our consolidated financial statements included in this Annual Report). In addition, we recorded a net gain of $8.5 million due to the sale of three natural gas liquids terminals and we recorded a net gain of $0.8 million related to the retirement or sale of certain other assets. Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2025 2024 Change (in thousands) Other revenues: Service revenues $ 401 $ — $ 401 Cost of sales: Derivative gain — (937) 937 Expenses: General and administrative expenses 39,592 105,147 (65,555) Depreciation and amortization expense 3,027 4,749 (1,722) Loss (gain) on disposal or impairment of assets, net 43 (720) 763 Total expenses 42,662 109,176 (66,514) Operating loss $ (42,261) $ (108,239) $ 65,978 Service Revenues. These revenues relate to billings to the noncontrolling interest holders for usage of the airplanes acquired in June and October 2024. Cost of Sales - Derivative Gain. Our cost of sales during the year ended March 31, 2024 included $0.2 million of net realized losses on derivatives and $1.2 million of net unrealized gains on derivatives. We entered into economic hedges to protect our liquidity positions and leverage from a significant increase in commodity prices that drive our working capital demands. There were no open hedge positions that would impact cost of sales as of March 31, 2025. General and Administrative Expenses . The decrease during the year ended March 31, 2025 is primarily due to the increase in our accrual as of March 31, 2024, related to the LCT Capital, LLC (“LCT”) legal matter (see Note 8 to our consolidated financial statements included in this Annual Report and also in the section below discussing the segment operating results for the years ended March 31, 2024 and 2023). The decrease also relates to lower legal expenses as several large cases ended and lower business insurance expense as we paid an insurance company in the prior year for the release of any supplementary calls related to our former crude marine business. Compensation expense was also lower due to the elimination of the share-based compensation expense due to all outstanding long-term incentive plan awards being fully vested in November 2023. Depreciation and Amortization Expense. The decrease during the year ended March 31, 2025 was due to software that became fully depreciated during the year ended March 31, 2024. Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2025, we recorded a net loss of less than $0.1 million due to the write-off of information technology equipment. During the year ended March 31, 2024, we sold an airplane for a gain of $0.7 million. Equity in Earnings of Unconsolidated Entities Equity in earnings of unconsolidated entities was $6.6 million during the year ended March 31, 2025, compared to $4.1 million during the year ended March 31, 2024. The increase of $2.5 million during the year ended March 31, 2025 was due primarily to higher earnings from certain membership interests related to specific land and water services operations. 62 Interest Expense The following table summarizes the components of our consolidated interest expense for the periods indicated: Year Ended March 31, 2025 2024 Change (in thousands) Senior secured notes $ 182,000 $ 160,088 $ 21,912 Senior secured term loan “B” credit facility (“Term Loan B”) 63,118 11,275 51,843 ABL Facility 20,893 15,645 5,248 Senior unsecured notes — 40,829 (40,829) Other indebtedness 1,630 26,781 (25,151) Total debt interest expense 267,641 254,618 13,023 Amortization of debt issuance costs 12,010 15,701 (3,691) Unrealized loss (gain) on interest rate swaps 3,054 (515) 3,569 Realized gain on interest rate swaps (2,627) — (2,627) Total interest expense $ 280,078 $ 269,804 $ 10,274 The debt interest expense increased $13.0 million during the year ended March 31, 2025 primarily due to higher interest rates on the Term Loan B, the 8.125% senior secured notes due 2029 (“2029 Senior Secured Notes”) and the 8.375% senior secured notes due 2032 (“2032 Senior Secured Notes”). This was partially offset by the repurchase/redemption of the 6.125% senior unsecured notes due 2025 (“2025 Notes”) and the redemption of the 7.5% senior unsecured notes due 2026 (“2026 Notes”) (collectively, the “Senior Unsecured Notes”) during the year ended March 31, 2024. Also, in the prior year we had an interest accrual of $26.1 million, included in other indebtedness, related to the LCT legal matter (see Note 8 to our consolidated financial statements included in this Annual Report). Loss on Early Extinguishment of Liabilities, Net Loss on early extinguishment of liabilities, net was $55.3 million during the year ended March 31, 2024. During the year ended March 31, 2024, the net loss (inclusive of debt issuance costs written off) primarily relates to the call premium of $38.4 million paid for the early extinguishment of the outstanding 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”), the write-off of debt issuance costs and other expenses related to the repurchase/redemption of the 2026 Senior Secured Notes and Senior Unsecured Notes during the fiscal year. We did not repurchase any debt during the year ended March 31, 2025. See Note 7 to our consolidated financial statements included in this Annual Report for a further discussion of the debt instruments repurchased and redeemed. Other Income, Net Other income, net of $4.3 million during the year ended March 31, 2025 consisted primarily of a gain on the expiration of an option, realized and unrealized gains on marketable securities, interest income on loan receivables (see Note 2 to our consolidated financial statements included in this Annual Report for a further discussion) and unrealized losses on investments. Other income, net of $2.8 million during the year ended March 31, 2024 consisted primarily of interest income on loan receivables and cash on hand, income from the settlement of a dispute and income from excess distributions received from an equity method investee. Income Tax Benefit (Expense) Income tax benefit was $4.9 million during the year ended March 31, 2025, compared to income tax expense of $1.5 million during the year ended March 31, 2024. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion. Noncontrolling Interests - Redeemable and Nonredeemable Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third-parties. Noncontrolling interest income was $3.8 million during the year ended March 31, 2025, compared to $0.6 million during the year ended March 31, 2024. The increase of $3.2 million during the year ended March 31, 2025 was due primarily to higher income from certain water solutions operations. 63 Segment Operating Results for the Years Ended March 31, 2024 and 2023 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated. Year Ended March 31, 2024 2023 Change (in thousands, except per barrel and per day amounts) Revenues: Water disposal service fees $ 572,972 $ 524,689 $ 48,283 Sale of recovered crude oil 107,367 120,705 (13,338) Recycled water 9,785 13,841 (4,056) Other revenues 40,694 37,803 2,891 Total revenues 730,818 697,038 33,780 Expenses: Cost of sales-excluding impact of derivatives 10,146 9,737 409 Derivative loss 1,148 4,363 (3,215) Operating expenses 212,052 212,115 (63) General and administrative expenses 5,417 8,722 (3,305) Depreciation and amortization expense 214,480 207,081 7,399 Loss on disposal or impairment of assets, net 53,639 46,431 7,208 Revaluation of liabilities 2,680 9,665 (6,985) Total expenses 499,562 498,114 1,448 Segment operating income $ 231,256 $ 198,924 $ 32,332 Produced water processed (barrels per day) Delaware Basin 2,123,337 2,042,777 80,560 Eagle Ford Basin 142,374 119,458 22,916 DJ Basin 150,426 150,619 (193) Other Basins 740 14,483 (13,743) Total 2,416,877 2,327,337 89,540 Recycled water (barrels per day) 84,212 118,847 (34,635) Total (barrels per day) 2,501,089 2,446,184 54,905 Skim oil sold (barrels per day) (1) 3,992 3,764 228 Service fees for produced water processed ($/barrel) (2)(3) $ 0.65 $ 0.62 $ 0.03 Recovered crude oil for produced water processed ($/barrel) (2) $ 0.12 $ 0.14 $ (0.02) Operating expenses for produced water processed ($/barrel) (2) $ 0.24 $ 0.25 $ (0.01) (1) As of March 31, 2023, approximately 34,380 barrels of skim oil were stored and were sold during the year ended March 31, 2024. (2) Total produced water barrels processed during the years ended March 31, 2024 and 2023 were 884,576,981 and 849,477,938, respectively. These amounts do not include 63,968,944 barrels and 36,143,594 barrels for the years ended March 31, 2024 and 2023, respectively, related to payments made by certain producers for committed volumes not delivered, as discussed further below. (3) Excluding payments made by certain producers for committed volumes not delivered and the one-time item discussed below, service fees for produced water processed ($/barrel) would have been $0.61/barrel and $0.59/barrel during the years ended March 31, 2024 and 2023, respectively. Water Disposal Service Fee Revenues. The increase was due primarily to an increase in produced water volumes processed from contracted customers mainly in the Delaware Basin, increased fees from new contracts and higher fees charged for interruptible spot volumes. There was also an increase in payments made by certain producers for committed volumes not delivered. Service fees for produced water processed ($/barrel) also benefited from these deficiency payments. In addition, during July 2023, we entered into a transaction in which a portion of the total consideration received was allocated to revenue due to the termination of a minimum volume water disposal contract (see Note 17 to our consolidated financial statements included in this Annual Report). 64 Recovered Crude Oil Revenues. The decrease was due primarily to lower realized crude oil prices received from the sale of skim oil barrels, partially offset by an increase in skim oil barrels sold as a result of higher skim oil recovered from increased produced water processed. In addition, during the current fiscal year we sold 34,380 barrels of skim oil that were stored as of March 31, 2023 due to tighter pipeline specifications. Recycled Water Revenues. The decrease was due primarily to lower recycled water volumes related to timing of water to be used in completions. Other Revenues. The increase was due primarily to higher reimbursements from construction projects, booster operating fees and generator rentals, higher land surface use revenues and higher lease revenue from certain surface use and compensation agreements. These increases were partially offset by lower water pipeline revenues due to the expiration of certain pipeline commitment revenue in December 2022 and lower sales of brackish non-potable water related to the timing of our customers transitioning from brackish non-potable water to recycled water. Cost of Sales-Excluding Impact of Derivatives . The increase was due primarily to costs incurred that will be reimbursed by producers for generator and fuel costs at various booster stations. In addition, we incurred increased trucking expenses for skim oil sales during the year ended March 31, 2024. These increases were partially offset by lower recycling costs due to a decrease in recycling activity and lower 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, 2024, we had $0.4 million of net unrealized losses on derivatives and $0.8 million of net realized losses on derivatives. During the year ended March 31, 2023, we had $4.5 million of net unrealized gains on derivatives and $8.8 million of net realized losses on derivatives. Operating and General and Administrative Expenses . The decrease was due primarily to lower chemical expense due to purchasing fewer chemicals and using chemicals more efficiently, lower overhead costs, lower generator rental expense due to renting fewer generators and lower severance taxes due to a decrease in revenue from recovered crude oil and a severance tax refund in September 2023 related to prior periods. These decreases were partially offset by higher operating expenses due to increased produced water volumes processed. Depreciation and Amortization Expense . The increase was due primarily to depreciation of newly developed facilities and infrastructure, partially offset by certain long-term assets being fully amortized or impaired during the fiscal years ended March 31, 2023 and 2024. Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2024, we recorded a net loss of $37.5 million primarily related to the write down of the value of certain saltwater disposal wells as well as the abandonment of certain capital projects and the retirement of certain assets, a net loss of $17.6 million primarily related to the sale of certain assets and an impairment of $2.4 million for certain leases due to underutilization of certain freshwater wells. In addition, we recorded a gain of $3.9 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period. During the year ended March 31, 2023, we recorded a net loss of $26.3 million primarily related to the sale of certain assets and a net loss of $21.8 million to write down the value of an inactive saltwater disposal facility and damaged equipment at another saltwater disposal facility, as well as the abandonment of certain capital projects and the retirement of certain assets. We also recorded a loss of $0.5 million related to the termination of a joint marketing agreement. In addition, we recorded a gain of $2.1 million from an insurance recovery for a saltwater disposal facility damaged in a prior period. Revaluation of Liabilities. During the years ended March 31, 2024 and 2023, 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 produced water volumes from our customers, resulting in an increase to the expected future royalty payment. 65 Crude Oil Logistics The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated: Year Ended March 31, 2024 2023 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 1,597,238 $ 2,376,434 $ (779,196) Crude oil transportation and other sales 59,373 96,978 (37,605) Total revenues 1,656,611 2,473,412 (816,801) Expenses: Cost of sales-excluding impact of derivatives 1,514,370 2,274,089 (759,719) Derivative loss (gain) 7,367 (14,565) 21,932 Operating expenses 39,004 50,154 (11,150) General and administrative expenses 3,780 4,547 (767) Depreciation and amortization expense 36,922 46,577 (9,655) Loss on disposal or impairment of assets, net 3,094 31,086 (27,992) Total expenses 1,604,537 2,391,888 (787,351) Segment operating income $ 52,074 $ 81,524 $ (29,450) Crude oil sold (barrels) 20,068 25,497 (5,429) Crude oil transported on owned pipelines (barrels) 25,611 27,714 (2,103) Crude oil storage capacity - owned and leased (barrels) (1) 5,232 5,232 — Crude oil storage capacity leased to third-parties (barrels) (1) 2,250 1,501 749 Crude oil inventory (barrels) (1) 573 684 (111) Crude oil sold ($/barrel) $ 79.591 $ 93.204 $ (13.613) Cost per crude oil sold ($/barrel) (2) $ 75.462 $ 89.190 $ (13.728) Crude oil product margin ($/barrel) (2) $ 4.129 $ 4.014 $ 0.115 (1) Information is presented as of March 31, 2024 and March 31, 2023, respectively. (2) Cost and product margin per barrel excludes the impact of derivatives. Crude Oil Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to lower sales volumes due to lower production on acreage dedicated to us in the DJ Basin during the year ended March 31, 2024, compared to the year ended March 31, 2023 and a decrease in crude oil prices year over year. Crude oil product margin from the sale of crude oil decreased from $102.3 million for the year ended March 31, 2023 to $82.9 million during the year ended March 31, 2024, primarily due to lower volumes and lower crude oil prices year over year. The lower crude oil prices resulted in lower contracted rates with certain producers, compared to the prior year when the contracted rates were higher due to the higher crude oil prices. We also realized lower contract differentials on certain other sales contracts. Crude oil product margin per barrel increased during the year ended March 31, 2024, compared to the year ended March 31, 2023, due to the sale of lower priced inventory into a market in which prices were increasing during certain periods of 2024. Whereas during the year ended March 31, 2023, we were selling higher priced inventory into a market in which prices were generally declining throughout the fiscal year. Crude oil product margin calculations does not include gains and losses from derivatives that may offset the movement in the physical margin. Derivative Loss (Gain). Our cost of sales during the year ended March 31, 2024 included $58.4 million of net realized gains on derivatives and $65.8 million of net unrealized losses on derivatives. The amounts in the previous sentence for the year ended March 31, 2024 included net realized gains of $60.9 million and net unrealized losses of $61.4 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, 2023 included $35.5 million of net realized losses on derivatives and $50.1 million of net unrealized gains on derivatives. The amounts in the previous sentence for the year ended 66 March 31, 2023 includes net realized losses of $13.1 million and net unrealized gains of $23.8 million associated with derivative instruments related to our hedge of the CMA Differential Roll. Crude Oil Transportation and Other Sales. The decrease was primarily due to the sale of our marine assets on March 30, 2023, and lower pipeline tariff revenue due to the assignment of our commitment on a third-party pipeline. During the year ended March 31, 2024, physical volumes on the Grand Mesa Pipeline averaged approximately 70,000 barrels per day, compared to approximately 76,000 barrels per day for the year ended March 31, 2023. Lower contracted volumes were shipped on the Grand Mesa Pipeline due to lower production on acreage dedicated to us in the DJ Basin. Operating and General and Administrative Expenses . The decrease was primarily due to the sale of our marine assets on March 30, 2023. Additionally, the current year benefited from lower incentive compensation expense, as well as lower repairs and maintenance expense on leased railcars returned to the lessor in the prior year. Depreciation and Amortization Expense. The decrease was primarily due to the sale of our marine assets on March 30, 2023, lower depreciation expense due to certain of our railcar assets becoming fully depreciated during the year ended March 31, 2024 and the impairment of certain terminal assets in the prior year, which lowered their depreciable base. Loss on Disposal or Impairment of Assets, Net . During the year ended March 31, 2024, we recorded a net loss of $3.1 million primarily due to the retirement or sale of certain assets. During the year ended March 31, 2023, we recorded an impairment of $23.1 million related to an underperforming crude oil terminal and a loss of $8.0 million on the sale of our marine assets. 67 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated. As discussed above, the operating results of our refined products and biodiesel businesses have been classified as discontinued operations for all periods presented and prior periods have been retrospectively adjusted. Year Ended March 31, 2024 2023 Change (in thousands, except per gallon amounts) Propane: Sales $ 739,591 $ 1,161,129 $ (421,538) Cost of sales-excluding impact of derivatives 692,649 1,103,786 (411,137) Derivative loss 2,463 11,642 (9,179) Product margin 44,479 45,701 (1,222) Butane: Sales 628,685 773,633 (144,948) Cost of sales-excluding impact of derivatives 587,307 776,845 (189,538) Derivative loss (gain) 2,771 (22,976) 25,747 Product margin 38,607 19,764 18,843 Other products: Sales -excluding impact of derivatives 383,998 568,180 (184,182) Cost of sales-excluding impact of derivatives 367,293 551,053 (183,760) Derivative loss 25 1,246 (1,221) Product margin 16,680 15,881 799 Service: Sales 14,151 14,218 (67) Cost of sales 1,379 1,603 (224) Product margin 12,772 12,615 157 Expenses: Operating expenses 48,549 42,320 6,229 General and administrative expenses 7,281 7,236 45 Depreciation and amortization expense 9,963 12,788 (2,825) Loss on disposal or impairment of assets, net 59,923 10,171 49,752 Total expenses 125,716 72,515 53,201 Segment operating (loss) income $ (13,178) $ 21,446 $ (34,624) Natural gas liquids storage capacity - owned and leased (gallons) (1) 122,831 152,719 (29,888) Propane sold (gallons) 811,035 1,018,937 (207,902) Propane sold ($/gallon) $ 0.912 $ 1.140 $ (0.228) Cost per propane sold ($/gallon) (2) $ 0.854 $ 1.083 $ (0.229) Propane product margin ($/gallon) (2) $ 0.058 $ 0.057 $ 0.001 Propane inventory (gallons) (1) 35,177 48,379 (13,202) Butane sold (gallons) 537,015 539,658 (2,643) Butane sold ($/gallon) $ 1.171 $ 1.434 $ (0.263) Cost per butane sold ($/gallon) (2) $ 1.094 $ 1.440 $ (0.346) Butane product margin (loss) ($/gallon) (2) $ 0.077 $ (0.006) $ 0.083 Butane inventory (gallons) (1) 17,790 17,409 381 Other products sold (gallons) 263,422 318,511 (55,089) Other products sold ($/gallon) $ 1.458 $ 1.784 $ (0.326) Cost per other products sold ($/gallon) (2) $ 1.394 $ 1.730 $ (0.336) Other products product margin ($/gallon) (2) $ 0.064 $ 0.054 $ 0.010 Other products inventory (gallons) (1) 5,623 3,889 1,734 68 (1) Information is presented as of March 31, 2024 and March 31, 2023, respectively. (2) Cost and product margin (loss) per gallon excludes the impact of derivatives. Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due to lower propane volumes and lower prices during the year ended March 31, 2024. Propane volumes decreased during the year ended March 31, 2024 due to the sale of three natural gas liquids terminals, the loss of a certain supply contract, lower performing natural gas liquids terminals being idled and a focus on more profitable markets and customers. Also, demand was lower during the year ended March 31, 2024 due to the warmer than normal winter. Propane product margins, excluding the impact of derivatives, decreased during the year ended March 31, 2024 primarily due to lower volumes and lower prices. Propane Derivative Loss. Our cost of propane sales included $4.6 million of net unrealized gains on derivatives and $7.0 million of net realized losses on derivatives during the year ended March 31, 2024. During the year ended March 31, 2023, our cost of propane sales included $6.9 million of net unrealized losses on derivatives and $4.7 million of net realized losses on derivatives. Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to lower butane prices. The decrease was also due to lower volumes during the first six months of the year ended March 31, 2024 as a result of weak spot demand, weak export demand and a change in strategy by a significant customer. These decreases were partially offset by strong blending demand from October 2023 through February 15, 2024. Butane product margins, excluding the impact of derivatives, increased during the year ended March 31, 2024, as compared to the year ended March 31, 2023, primarily due to higher demand for butane blending which has tightened up the butane supply, causing sales differentials to increase. Also, in the prior year, we were negatively impacted by lower location differentials as the product we contracted to purchase in the beginning of the season was continuing to compete with product purchased in the discounted market. Butane Derivative Loss (Gain). Our cost of butane sales during the year ended March 31, 2024 included $3.2 million of net unrealized losses on derivatives and $0.5 million of net realized gains on derivatives. Our cost of butane sales included $3.9 million of net unrealized gains on derivatives and $19.1 million of net realized gains on derivatives during the year ended March 31, 2023. Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to the decrease in market prices during the year ended March 31, 2024 as compared to the year ended March 31, 2023. The decrease was also the result of lower natural gasoline volumes due to the loss of certain supply contracts. These decreases were partially offset by increased sales of asphalt due to increased supply. Other products sales product margins, excluding the impact of derivatives, decreased during the year ended March 31, 2024, mainly due to loss of certain supply contracts for natural gasoline as well as decreased market prices for natural gasoline. Other Products Derivative Loss. Our derivatives of other products included $0.1 million of net realized gains on derivatives and $0.1 million of net unrealized losses on derivatives during the year ended March 31, 2024. Our derivatives of other products during the year ended March 31, 2023 included $1.3 million of net realized losses on derivatives and $0.1 million of net unrealized gains on derivatives. Service Sales and Cost of Sales. The sales include storage, terminaling and transportation services income. Sales during the year ended March 31, 2024 remained consistent with the year ended March 31, 2023 but cost of sales decreased due to lower third-party costs. Operating and General and Administrative Expenses. The increase was due to higher incentive compensation due to improved margins in certain of our businesses year over year. Depreciation and Amortization Expense. The decrease was due to a customer relationship intangible asset being fully amortized as of June 30, 2023. 69 Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2024, we recorded a goodwill impairment loss of $69.2 million in our Wholesale/Terminal reporting unit (see Note 5 to our consolidated financial statements included in this Annual Report). In addition, we recorded a net gain of $8.5 million due to the sale of three natural gas liquids terminals and we recorded a net gain of $0.8 million related to the retirement or sale of certain other assets. During the year ended March 31, 2023, we recorded a net loss of $10.1 million due to the impairment of several underperforming natural gas liquids terminals. In addition, during the year ended March 31, 2023, we recorded a net loss of $0.1 million related to the sale and retirement of other assets. Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2024 2023 Change (in thousands) Cost of sales: Derivative (gain) loss $ (937) $ 1,181 $ (2,118) Expenses: General and administrative expenses 105,147 50,978 54,169 Depreciation and amortization expense 4,749 6,662 (1,913) Gain on disposal or impairment of assets, net (720) (912) 192 Total expenses 109,176 56,728 52,448 Operating loss $ (108,239) $ (57,909) $ (50,330) Cost of Sales - Derivative (Gain) Loss. Our cost of sales during the year ended March 31, 2024 included $0.2 million of net realized losses on derivatives and $1.2 million of net unrealized gains on derivatives. We entered into economic hedges to protect our liquidity positions and leverage from a significant increase in commodity prices that drive our working capital demands, as we experienced in the prior fiscal year, thus impacting our ability to reduce absolute indebtedness until commodity prices weakened. There were no open hedge positions that would impact cost of sales as of March 31, 2024. General and Administrative Expenses . The increase during the year ended March 31, 2024 relates primarily to the increase in our accrual related to the LCT legal matter from $2.5 million to $36.0 million (see Note 8 to our consolidated financial statements included in this Annual Report), and the write-off of $14.2 million of legal costs related to the LCT legal matter that were originally allocated to the GP. In addition, we also incurred increased business insurance expense as we paid the insurance company to be released from any future supplementary calls on our indemnity policy related to our former crude marine business (which we sold on March 30, 2023), increased insurance premiums and a reduction in our corporate overhead allocation to the other business segments. These increases were partially offset by a decrease in equity-based incentive compensation as our final service award vested on November 15, 2023. Depreciation and Amortization Expense. The decrease during the year ended March 31, 2024 was due to software that became fully depreciated during the year ended March 31, 2024. Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2024, we sold an airplane for a gain of $0.7 million. During the year ended March 31, 2023, we sold an airplane for a gain of $1.3 million, which was partially offset by a loss recorded to write-off the remaining amount of a loan receivable, due July 31, 2023, that was prepaid by the debtor and an impairment loss recorded on the sublease of a building we were no longer using. Equity in Earnings of Unconsolidated Entities Equity in earnings of unconsolidated entities of $4.1 million during the year ended March 31, 2024 consisted primarily of earnings from certain membership interests related to specific land and water services operations and earnings from another entity due to a gain recognized on the sale of an airplane during the three months ended December 31, 2023. Equity in earnings of unconsolidated entities of $4.1 million during the year ended March 31, 2023 consisted primarily of earnings from certain membership interests related to specific land and water services operations and a loss from our interest in an aircraft company. 70 Interest Expense The following table summarizes the components of our consolidated interest expense for the periods indicated: Year Ended March 31, 2024 2023 Change (in thousands) Senior secured notes $ 160,088 $ 153,750 $ 6,338 Senior unsecured notes 40,829 76,288 (35,459) ABL Facility 15,645 17,111 (1,466) Term Loan B 11,275 — 11,275 Other indebtedness 26,781 11,552 15,229 Total debt interest expense 254,618 258,701 (4,083) Amortization of debt issuance costs 15,701 16,737 (1,036) Unrealized gain on interest rate swaps (515) — (515) Total interest expense $ 269,804 $ 275,438 $ (5,634) The debt interest expense decreased $4.1 million during the year ended March 31, 2024 primarily due to the repurchase of the 7.5% senior unsecured notes due 2023 (“2023 Notes”) throughout the prior year and the redemption of the remaining 2023 Notes on March 31, 2023. In addition, we repurchased a portion of the outstanding 2025 Notes during the three months ended June 30, 2023. Also, in the prior year, we had an accrual of the settlement of a claim for the failure to pay interest on royalty payments. These decreases were partially offset by $26.1 million of interest accrued related to the LCT legal matter (see Note 8 to our consolidated financial statements included in this Annual Report) and an increase due to higher interest rates on the new debt instruments. (Loss) Gain on Early Extinguishment of Liabilities, Net Loss on early extinguishment of liabilities, net was $55.3 million during the year ended March 31, 2024, compared to a gain on early extinguishment of liabilities, net of $6.2 million during the year ended March 31, 2023. During the year ended March 31, 2024, the net loss (inclusive of debt issuance costs written off) primarily relates to the call premium of $38.4 million paid for the early extinguishment of the outstanding 2026 Senior Secured Notes, the write-off of debt issuance costs and other expenses related to the repurchase/redemption of the 2026 Senior Secured Notes and Senior Unsecured Notes during the fiscal year. During the year ended March 31, 2023, the net gain (inclusive of debt issuance costs written off) primarily related to the early extinguishment of a portion of the outstanding Senior Unsecured Notes partially offset by the write-off of debt issuance costs. In addition, we paid a prepayment premium of $1.6 million and wrote off debt issuance costs of less than $0.1 million related to the payoff of an outstanding equipment loan. See Note 7 to our consolidated financial statements included in this Annual Report for a further discussion of the debt instruments repurchased and redeemed. Other Income, Net Other income, net of $2.8 million during the year ended March 31, 2024 consisted primarily of interest income on loan receivables (see Note 2 to our consolidated financial statements included in this Annual Report for a further discussion) and cash on hand, income from the settlement of a dispute and income from excess distributions received from an equity method investee. Other income, net of $30.4 million during the year ended March 31, 2023 consisted primarily of a settlement of a dispute associated with commercial activities not occurring in the current reporting periods (see Note 17 to our consolidated financial statements included in this Annual Report for a further discussion). Income Tax Expense Income tax expense was $1.5 million during the year ended March 31, 2024, compared to income tax expense of $0.2 million during the year ended March 31, 2023. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion. Noncontrolling Interests - Redeemable and Nonredeemable Noncontrolling interest income was $0.6 million during the year ended March 31, 2024, compared to $1.1 million during the year ended March 31, 2023. The decrease of $0.5 million during the year ended March 31, 2024 was due primarily to lower income from certain water solutions operations during the year ended March 31, 2024. 71 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, revaluation of liabilities and other. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income (loss), income (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. 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. 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 differed from period to period depending on the current crude oil price and future estimated crude oil price which were valued utilizing third-party market quoted prices. We recognized 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 hedged each month through the term of this transaction. This representation aligns with management’s evaluation of the transaction. The derivative instrument positions we entered into related to the CMA Differential Roll expired as of December 31, 2023, and we have not entered into any new derivative instrument positions related to the CMA Differential Roll. As previously reported, for purposes of our Adjusted EBITDA calculation, we did not draw a distinction between realized and unrealized gains and losses on derivatives of certain businesses within our Liquids Logistics segment, which are included in discontinued operations. 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. We include this in Adjusted EBITDA because the unrealized gains and losses for 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. Beginning April 1, 2024, and going forward, we will now be drawing a distinction between realized and unrealized gains and losses on derivatives and will no longer include the activity on the “inventory valuation adjustment” row in the reconciliation table for these certain businesses within our Liquids Logistics segment, which are included in discontinued operations. This change aligns with how management now views and evaluates the transactions within these businesses and is also consistent with the calculation of Adjusted EBITDA used in our other businesses. If this change was made as of April 1, 2022, Adjusted EBITDA for the years ended March 31, 2023 and 2024 would have been $638.8 million and $609.5 million, respectively. 72 The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA for the periods indicated: Year Ended March 31, 2025 2024 2023 (in thousands) Net income (loss) $ 43,163 $ (143,124) $ 52,492 Less: Net income from continuing operations attributable to nonredeemable noncontrolling interests (3,749) (631) (1,106) Less: Net income from continuing operations attributable to redeemable noncontrolling interests (46) — — Net income (loss) attributable to NGL Energy Partners LP 39,368 (143,755) 51,386 Interest expense 280,241 270,004 275,505 Income tax (benefit) expense (4,775) 2,405 271 Depreciation and amortization 253,190 266,287 273,544 EBITDA 568,024 394,941 600,706 Net unrealized losses (gains) on derivatives 21,782 63,762 (50,438) Lower of cost or net realizable value adjustments (1) (1,619) 1,337 (11,534) Loss on disposal or impairment of assets, net (2) 33,705 115,555 86,872 Revaluation of liabilities (6,705) 2,680 9,665 CMA Differential Roll net losses (gains) (3) — (71,285) 3,547 Inventory valuation adjustment (4) — (3,419) (7,795) Loss (gain) on early extinguishment of liabilities, net — 55,281 (6,177) Equity-based compensation expense — 1,098 2,718 Other (5) 2,572 50,131 5,111 Adjusted EBITDA $ 617,759 $ 610,081 $ 632,675 Adjusted EBITDA - Discontinued Operations (6) $ (5,133) $ 16,667 $ 39,066 Adjusted EBITDA - Continuing Operations $ 622,892 $ 593,414 $ 593,609 (1) Lower of cost or net realizable value adjustments in the table above differ from lower of cost or net realizable value adjustments reported in our consolidated statements of cash flows, as the amounts reported in the table above represent the change in lower of cost or net realizable value adjustments recorded in the consolidated statements of operations, which includes reversals, whereas the amounts reported in our consolidated statements of cash flows represent the lower of cost or net realizable value adjustments recorded at the balance sheet date. (2) Excludes amounts related to unconsolidated entities and noncontrolling interests. (3) 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. (4) Amounts represent the difference between the market value of the inventory at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion. (5) Amounts represent accretion expense for asset retirement obligations, unrealized gains and losses on investments and marketable securities and expenses incurred related to legal and advisory costs associated with acquisitions and dispositions, including the accrued judgment related to the LCT legal matter, excluding interest (see Note 8 to our consolidated financial statements included in this Annual Report), and the write-off of the legal costs related to the LCT legal matter that were originally allocated to the GP. Also, the amount for the year ended March 31, 2023 includes the write off of an asset acquired in a prior period acquisition and non-cash operating expenses related to our Grand Mesa Pipeline. (6) Amounts include our refined products and biodiesel businesses. 73 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, 2025 2024 2023 (in thousands) Depreciation and amortization per EBITDA table $ 253,190 $ 266,287 $ 273,544 Intangible asset amortization recorded to cost of sales (257) — (14) Depreciation and amortization attributable to unconsolidated entities (426) (686) (783) Depreciation and amortization attributable to noncontrolling interests 2,708 1,182 1,134 Depreciation and amortization attributable to discontinued operations (483) (669) (773) Depreciation and amortization per consolidated statements of operations $ 254,732 $ 266,114 $ 273,108 Depreciation and amortization per EBITDA table $ 253,190 $ 266,287 $ 273,544 Amortization of debt issuance costs recorded to interest expense 12,010 15,701 16,737 Amortization of royalty expense recorded to operating expense 247 247 247 Depreciation and amortization attributable to unconsolidated entities (426) (686) (783) Depreciation and amortization attributable to noncontrolling interests 2,708 1,182 1,134 Depreciation and amortization attributable to discontinued operations (483) (669) (773) Depreciation and amortization per consolidated statements of cash flows $ 267,246 $ 282,062 $ 290,106 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, 2025 2024 2023 (in thousands) Interest expense per EBITDA table $ 280,241 $ 270,004 $ 275,505 Interest expense attributable to noncontrolling interests 63 — — Interest expense attributable to unconsolidated entities (1) (81) (60) Interest expense attributable to discontinued operations (225) (119) (7) Interest expense per consolidated statements of operations $ 280,078 $ 269,804 $ 275,438 The following table summarizes additional amounts attributable to discontinued operations in the EBITDA and Adjusted EBITDA table above for the periods indicated: Year Ended March 31, 2025 2024 2023 (in thousands) Income tax expense $ 110 $ 947 $ 52 Net unrealized losses on derivatives $ 18,416 $ — $ — Lower of cost or realizable value adjustments $ (4,535) $ 3,745 $ 790 Loss on disposal or impairment of assets, net $ 1,995 $ — $ 112 Inventory valuation adjustment $ — $ (3,419) $ (7,795) Other $ — $ 1 $ 1,670 74 The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. Year Ended March 31, 2025 Water Solutions Crude Oil Logistics Liquids Logistics Corporate and Other Continuing Operations Discontinued Operations Consolidated (in thousands) Operating income (loss) $ 311,457 $ 46,101 $ 14,058 $ (42,261) $ 329,355 $ — $ 329,355 Depreciation and amortization 217,227 25,070 9,408 3,027 254,732 — 254,732 Amortization recorded to cost of sales — — 257 — 257 — 257 Net unrealized losses (gains) on derivatives 4,953 (4,011) 2,424 — 3,366 — 3,366 Lower of cost or net realizable value adjustments — — 2,916 — 2,916 — 2,916 Loss (gain) on disposal or impairment of assets, net 9,813 (1,004) 22,596 43 31,448 — 31,448 Other income, net 485 1 1,518 2,258 4,262 — 4,262 Adjusted EBITDA attributable to unconsolidated entities 7,044 — (51) — 6,993 — 6,993 Adjusted EBITDA attributable to noncontrolling interest (6,196) — — (178) (6,374) — (6,374) Revaluation of liabilities (6,705) — — — (6,705) — (6,705) Other 3,918 216 243 (1,735) 2,642 — 2,642 Discontinued operations — — — — — (5,133) (5,133) Adjusted EBITDA $ 541,996 $ 66,373 $ 53,369 $ (38,846) $ 622,892 $ (5,133) $ 617,759 Year Ended March 31, 2024 Water Solutions Crude Oil Logistics Liquids Logistics Corporate and Other Continuing Operations Discontinued Operations Consolidated (in thousands) Operating income (loss) $ 231,256 $ 52,074 $ (13,178) $ (108,239) $ 161,913 $ — $ 161,913 Depreciation and amortization 214,480 36,922 9,963 4,749 266,114 — 266,114 Net unrealized losses (gains) on derivatives 385 65,786 (1,230) (1,179) 63,762 — 63,762 CMA Differential Roll net losses (gains) — (71,285) — — (71,285) — (71,285) Lower of cost or net realizable value adjustments — — (2,408) — (2,408) — (2,408) Loss (gain) on disposal or impairment of assets, net 53,639 3,094 59,923 (720) 115,936 — 115,936 Equity-based compensation expense — — — 1,098 1,098 — 1,098 Other income, net 1,110 105 1 1,566 2,782 — 2,782 Adjusted EBITDA attributable to unconsolidated entities 4,393 — (12) 124 4,505 — 4,505 Adjusted EBITDA attributable to noncontrolling interest (1,821) — — — (1,821) — (1,821) Revaluation of liabilities 2,680 — — — 2,680 — 2,680 Other 2,186 191 228 47,533 50,138 — 50,138 Discontinued operations — — — — — 16,667 16,667 Adjusted EBITDA $ 508,308 $ 86,887 $ 53,287 $ (55,068) $ 593,414 $ 16,667 $ 610,081 75 Year Ended March 31, 2023 Water Solutions Crude Oil Logistics Liquids Logistics Corporate and Other Continuing Operations Discontinued Operations Consolidated (in thousands) Operating income (loss) $ 198,924 $ 81,524 $ 21,446 $ (57,909) $ 243,985 $ — $ 243,985 Depreciation and amortization 207,081 46,577 12,788 6,662 273,108 — 273,108 Amortization recorded to cost of sales — — 14 — 14 — 14 Net unrealized (gains) losses on derivatives (4,464) (50,104) 2,951 1,179 (50,438) — (50,438) CMA Differential Roll net losses (gains) — 3,547 — — 3,547 — 3,547 Lower of cost or net realizable value adjustments — (2,247) (10,077) — (12,324) — (12,324) Loss (gain) on disposal or impairment of assets, net 46,431 31,086 10,171 (912) 86,776 — 86,776 Equity-based compensation expense — — — 2,718 2,718 — 2,718 Other income (expense), net 70 330 (3) 30,013 30,410 — 30,410 Adjusted EBITDA attributable to unconsolidated entities 4,759 — 27 176 4,962 — 4,962 Adjusted EBITDA attributable to noncontrolling interest (2,269) — — — (2,269) — (2,269) Revaluation of liabilities 9,665 — — — 9,665 — 9,665 Other 2,894 203 263 95 3,455 — 3,455 Discontinued operations — — — — — 39,066 39,066 Adjusted EBITDA $ 463,091 $ 110,916 $ 37,580 $ (17,978) $ 593,609 $ 39,066 $ 632,675 Liquidity, Sources of Capital and Capital Resource Activities General Our principal sources of liquidity and capital resource requirements are cash flows from our operations, borrowings under the ABL Facility, issuing long-term notes, common and/or preferred units, loans from financial institutions, asset securitizations or asset sales. We expect our primary cash outflows to be related to capital expenditures, interest, repayment of debt maturities and distributions. 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 propane 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. In addition, our working capital borrowing needs vary with changes in commodity prices. A significant increase in commodity prices could drive up our working capital demands and limit our ability to continue to delever our balance sheet and restrict our financial flexibility. To protect our liquidity and leverage, we have in the past and may in the future enter into economic hedges that mitigate this exposure when we are building inventory. There were no open hedge positions as of March 31, 2025. 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 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. 76 Short-Term Liquidity Our principal sources of short-term liquidity consist of cash flows from our operations and borrowings under the ABL Facility, which we believe will provide liquidity to operate our business, manage our working capital requirements and repay current maturities. On February 2, 2024, we amended the ABL Facility to, among other things, (i) extend the maturity to the earliest of (a) February 2, 2029 and (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, subject to certain exceptions, (ii) provide for a sub-limit of $200.0 million for letters of credit and a $200.0 million incremental facility, subject to the receipt of commitments from lenders and customary borrowing conditions, (iii) modify the applicable margin for loans under the ABL Facility based on a secured overnight financing rate (“SOFR”) or the alternative base rate to provide for a 0.25% decrease based on our consolidated net leverage ratio, and (iv) provide for a mandatory prepayment under the ABL Facility while any loans are outstanding under the ABL Facility if aggregate “excess cash” (as defined in the ABL Facility) exceeds $50.0 million, subject to certain exceptions. Total commitments under the ABL Facility are $550.0 million. At March 31, 2025, $109.0 million was outstanding under the ABL Facility, letters of credit outstanding were $60.9 million, and we had a borrowing base of $397.7 million. For additional information related to the ABL Facility and the amendment, see Note 7 to our consolidated financial statements included in this Annual Report. As of March 31, 2025, our current assets exceeded our current liabilities by approximately $222.8 million. Long-Term Financing We expect to fund our long-term financing requirements by issuing long-term notes, common units and/or preferred units, loans from financial institutions, asset securitizations or asset sales. Senior Secured Notes On February 2, 2024, we closed on our private offering of $900.0 million of 2029 Senior Secured Notes that mature on February 15, 2029 and $1.3 billion of 2032 Senior Secured Notes that mature on February 15, 2032. Interest on the 2029 Senior Secured Notes and 2032 Senior Secured Notes is payable on February 15, May 15, August 15 and November 15 of each year. Term Loan B On February 2, 2024, we entered into a new seven-year $700.0 million Term Loan B. The Term Loan B matures on February 2, 2031 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.0% of the original principal amount, with the balance payable on maturity. The amount outstanding at March 31, 2025 is $693.0 million. 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, maintenance and other non-cash 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 Maintenance Other (1) Acquisitions (2) Investments (3) (in thousands) 2025 $ 175,730 $ 69,500 $ 20 $ — $ 106 2024 $ 99,533 $ 54,854 $ 15,680 $ — $ 258 2023 $ 79,091 $ 61,649 $ — $ — $ 88 (1) Amount for the year ended March 31, 2025 is related to a transaction classified as an acquisition of assets in a prior period. Amount for the year ended March 31, 2024 includes $9.2 million of equipment and other assets received in connection with contracts with customers 77 and $6.4 million for a transaction classified as an acquisition of assets. See Note 17 to our consolidated financial statements included in this Annual Report for information regarding the acquisition of assets. (2) There were no acquisitions during the years ended March 31, 2025, 2024 or 2023. (3) Amounts relate to contributions made to unconsolidated entities. Capital expenditures for the year ending March 31, 2026 are expected to be approximately $105 million. Distributions Declared On March 19, 2025, the board of directors of our GP declared a cash distribution for the quarter ended March 31, 2025 to the holders of the Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), the Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and the 9.00% Class D Preferred Units (“Class D Preferred Units”). The total distribution of $29.8 million was made on April 15, 2025 to the holder of record at the close of trading on April 1, 2025. The board of directors of our GP expects to evaluate the reinstatement of the common 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. For further discussion of the distributions, see Note 9 to our consolidated financial statements included in this Annual Report. Contractual Obligations Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, asset retirement obligations and other commitments. The amounts below do not include obligations related to liabilities classified as either held for sale or discontinued operations within our March 31, 2025 and 2024 consolidated balance sheets (see Note 18 to our consolidated financial statements included in this Annual Report). 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, 2025, our purchase commitments totaled $2.8 billion, with $2.5 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. Debt Principal and Interest Obligations As of March 31, 2025, our aggregate principal amount of outstanding debt was $3.0 billion, with $8.8 million due within one year. Our interest obligation on the debt was $1.4 billion, with $239.4 million due within one year, based on our outstanding balances and interest rates as of March 31, 2025. 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 debt principal and interest payments. Operating Lease Obligations As of March 31, 2025, our undiscounted operating lease obligation was $142.8 million, with $35.7 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. 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, 2025, our asset retirement obligations were $69.6 million, of which we expect to settle $2.5 million during fiscal year 2026. See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our asset retirement obligations. 78 Other Commitments We have noncancelable agreements for product storage, railcar spurs, capital projects and real estate. As of March 31, 2025, our commitment obligations were $30.0 million, with $9.7 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. Sources (Uses) of Cash The following table summarizes the sources (uses) of cash and cash equivalents for the periods indicated related to continuing operations (see the footnotes to our consolidated financial statements included in this Annual Report for the footnotes referenced in the table): Cash Flow Year Ended March 31, Category 2025 2024 2023 (in thousands) Sources of cash and cash equivalents: Net cash provided by operating activities-continuing operations Operating $ 256,850 $ 361,818 $ 355,685 Net proceeds from borrowings under ABL Facility (see Note 7) Financing 109,000 — 22,000 Proceeds from divestitures of businesses and investments, net (see Note 17) Investing 72,246 16,000 111,633 Proceeds from sales of assets (see Note 17) Investing 42,819 53,246 45,848 Proceeds from borrowings on other long-term debt (see Note 7) Financing 12,720 — — Issuance of secured debt (see Note 7) Financing — 2,894,873 — Net settlements of derivatives (see Note 10) Investing — — 56,005 Uses of cash and cash equivalents: Distributions to preferred unitholders (see Note 9) Financing (305,291) (178,299) — Capital expenditures (see Note 11) Investing (245,816) (152,295) (147,765) Payments on Term Loan B (see Note 7) Financing (7,000) — — Warrant repurchases (see Note 9) Financing (6,929) — — Debt issuance costs (see Note 6 and Note 7) Financing (5,258) (53,170) (3,294) Payments on other long-term debt (see Note 7) Financing (1,068) — (43,278) Net settlements of derivatives (see Note 10) Investing (246) (6,185) — Repayment and repurchase of Senior Unsecured Notes (see Note 7) Financing — (2,781,067) (479,302) Net payments on borrowings under ABL Facility (see Note 7) Financing — (138,000) — Other sources / (uses) – net Investing and Financing (2,192) (2,952) (3,979) Net (decrease) increase in cash and cash equivalents-continuing operations $ (80,165) $ 13,969 $ (86,447) Operating Activities-Continuing Operations. The decrease in net cash provided by operating activities during the year ended March 31, 2025 was due primarily to fluctuations in working capital, particularly accounts receivable and accounts payable, due to lower crude oil volumes and lower crude oil prices and the timing of invoices and payments on construction projects, partially offset by higher earnings from operations. Also, on June 13, 2024, we paid LCT $63.3 million related to the legal judgment against us, of which $27.2 million represented interest and $0.1 million of costs awarded to LCT (see Note 8 to our consolidated financial statements included in this Annual Report). The increase in net cash provided by operating activities during the year ended March 31, 2024 was due primarily to fluctuations in working capital, particularly accounts receivable and accounts payable, due to open derivative positions, partially offset by lower crude oil volumes and prices, lower inventory due to decreased sales and purchases of natural gas liquids, and decreased earnings from operations. 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 79 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, 2025 and 2024, we recorded goodwill impairments of $17.9 million and $69.2 million, respectively. We did not record a goodwill impairment during the year ended March 31, 2023. 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. When we cease to use an acquired trade name, we test the trade name for impairment using the relief from royalty method and we begin amortizing the trade name over its estimated useful life as a defensive asset. 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. 80 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 estimated useful 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 estimated useful 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. 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, and within cash flows from operations in our consolidated statements of cash flows. The change in the fair value of our interest rate swaps is recorded as a net gain or loss within interest expense in our consolidated statement of operations and within cash flows from operations in our consolidated statements of cash flows. 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–Commodity Price Risk” for the impact of a 10% increase in the underlying commodity value, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk–Interest Rate Risk” for the impact of a 10% increase in the underlying interest rate swap 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, 81 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 asset 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 over time. Our consolidated balance sheet at March 31, 2025 includes a liability of $69.6 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. Contingent Consideration Liabilities Certain business combinations in our Water Solutions segment included future royalty payments to the seller, which we recorded as contingent consideration liabilities as part of our purchase price allocation. The initial fair value was calculated based on an estimate of the activity related to the assets acquired in the transaction, either volumes or revenue, and an estimate of the expected useful life of the assets and discounted to its present value using an appropriate discount rate. The fair value of the contingent consideration liabilities is assessed each reporting period and the updated fair value is calculated using the same process used to calculate the initial fair value. Cha nges in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events. Our consolidated balance sheet at March 31, 2025 includes a liability of $15.8 million related to contingent consideration liabilities, which is recorded within accrued expenses and other payables and other noncurrent liabilities. 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 the 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 and natural gas liquids. 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. 82 Item 7A. Quantitative and Qualitative Disclosures About Market Risk Interest Rate Risk Long-Term Debt 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 prime rate or SOFR. At March 31, 2025, $109.0 million was outstanding under the ABL Facility at a weighted average interest rate of 9.50%. 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, 2025. The Term Loan B is variable-rate debt with interest rates that are generally indexed to the SOFR. At March 31, 2025, $693.0 million was outstanding under the Term Loan B with an interest rate of SOFR of 4.32% plus a margin of 3.75%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.9 million, based on borrowings outstanding at March 31, 2025. Interest Rate Swaps In March and April 2024, we entered into interest rate swaps totaling $400.0 million to reduce the variability of cash outflows associated with our floating-rate, SOFR-based borrowings, including borrowings on the Term Loan B. In September 2024, for the $200.0 million interest rate swap entered into in April 2024, we entered into a transaction to extend the original maturity date and to blend the existing swap rate (see Note 10 to our consolidated financial statements included in this Annual Report for a further discussion). An increase of 10% in the value of the underlying interest rate swaps would result in a net change in the fair value of our interest rate swaps of $0.3 million at March 31, 2025. Preferred Unit Distributions The current distribution rate for the Class B Preferred Units is a floating rate of the three-month CME Term SOFR plus a tenor spread adjustment plus a spread of 7.213% (see Note 9 to our consolidated financial statements included in this Annual Report for a further discussion). A change in interest rates of 0.125% would result in an increase or decrease of our Class B Preferred Unit distribution of $0.1 million, based on the Class B Preferred Units outstanding at March 31, 2025. The current distribution rate for the Class C Preferred Units is a floating rate of the three-month CME Term SOFR plus a spread of 7.384% (see Note 9 to our consolidated financial statements included in this Annual Report for a further discussion). A change in interest rates of 0.125% would result in an increase or decrease of our Class C Preferred Unit distribution of less than $0.1 million, based on the Class C Preferred Units outstanding at March 31, 2025. The current distribution rate for the Class D Preferred Units is a floating rate of the three-month CME Term SOFR plus a spread of 7.00%, as well as a 1.0% rate increase as we exceeded the adjusted total leverage ratio (as defined in the amended and restated limited partnership agreement) for the quarter ended March 31, 2025 (see Note 9 to our consolidated financial statements included in this Annual Report for a further discussion). A change in interest rates of 0.125% would result in an increase or decrease of our Class D Preferred Unit distribution of $0.2 million, based on the Class D Preferred Units outstanding at March 31, 2025. 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 or natural gas liquids 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 and natural gas liquids industries are “margin-based” and “cost-plus” businesses in which our realized margins depend on the differential of sales prices over our 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 and natural gas liquids. 83 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, and within cash flows from operations in our consolidated statements of cash flows. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Estimates” 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, 2025 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity. Amounts in the table below do not include commodity derivatives classified as either held for sale or discontinued operations within our March 31, 2025 and 2024 consolidated balance sheets (see Note 18 to our consolidated financial statements included in this Annual Report). Increase (Decrease) To Fair Value (in thousands) Crude oil (Crude Oil Logistics segment) $ 322 Butane (Liquids Logistics segment) $ (5,116) Other (Liquids Logistics segment) $ (83) 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; • 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, 2025, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. 84 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 (“Exchange Act”), that are designed to ensure 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 GP, 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 GP, of the effectiveness of the design and operation of our disclosure controls and procedures at March 31, 2025. Based on this evaluation, the principal executive officer and principal financial officer of our GP have concluded that as of March 31, 2025, such disclosure controls and procedures were effective. Management’s Report on Internal Control Over Financial Reporting The management of our Delaware limited partnership (“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, 2025. Our internal control over financial reporting as of March 31, 2025 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, 2025 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. 85 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, 2025, 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, 2025, 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, 2025, and our report dated May 29, 2025 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 May 29, 2025 86 Item 9B. Other Information During the three months ended March 31, 2025, no director or officer of the Partnership adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. 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 (“GP”), manages our operations and activities on our behalf through its directors and executive officers. Unitholders are not entitled to elect the directors of our GP or directly or indirectly participate in our management or operations. The NGL Energy GP investor group, which includes 43 individuals and entities that own all of the outstanding membership interests in our GP (“NGL Energy GP Investor Group”), appoints all members to the board of directors of our GP. The board of directors of our GP currently has six members. The board of directors of our GP has determined that Mr. James M. Collingsworth, 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 GP 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 GP 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 GP 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 GP 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. 87 Directors and Named Executive Officers Directors of our GP 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 GP. The following table summarizes information regarding the directors of our GP and our named executive officers as of May 27, 2025. Name Age Position with NGL Energy Holdings LLC H. Michael Krimbill 71 Chief Executive Officer and Director Bradley P. Cooper 49 Executive Vice President and Chief Financial Officer Lawrence J. Thuillier 54 Chief Accounting Officer L. Ryan Collins 39 Senior Vice President and General Counsel and Secretary Jennifer L. Kingham 53 Executive Vice President and Chief Information Officer Shawn W. Coady 63 Director James M. Collingsworth 70 Director Bryan K. Guderian 65 Director John T. Raymond 54 Director Derek S. Reiners 54 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 GP 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 the board of directors of our GP. Bradley P. Cooper . Mr. Cooper has served as our Executive Vice President and Chief Financial Officer since January 13, 2023. Mr. Cooper served as our Senior Vice President, Administration and Risk from June 2021, when he joined NGL, to January 2023. Mr. Cooper spent 10 years with WPX Energy, Inc. (“WPX”) where he was Vice President of Finance and Treasurer. Prior to WPX, he was at The Williams Companies (“Williams”) where he held various corporate finance and risk management leadership roles. Lawrence J. Thuillier. Mr. Thuillier has served as our Chief Accounting Officer since January 2016. Prior to joining NGL, Mr. Thuillier served in various roles at Eagle Rock Energy Partners, L.P. from December 2007 through October 2015, most recently as Vice President of Financial Reporting and Corporate Controller. Mr. Thuillier served as Assistant Corporate Controller for Exterran Holdings, Inc. (formerly Universal Compression) from November 2006 through November 2007. Prior to that, Mr. Thuillier served in various roles at Deloitte & Touche LLP, most recently as Audit Senior Manager. L. Ryan Collins. Mr. Collins has served as our Senior Vice President and General Counsel and Secretary since October 2024. Mr. Collins joined NGL in August 2015 and previously served as our Senior Vice President and Assistant General Counsel. Prior to joining NGL, Mr. Collins practiced law in the Tulsa, Oklahoma area, during which time his practice specialized in complex business transactions, real estate, banking, corporate governance, corporate management, and management of litigation. Jennifer L. Kingham . Ms. Kingham has served as our Executive Vice President and Chief Information Officer since March 2024. Ms. Kingham served as our Senior Vice President and Chief Information Officer from February 2018 to March 2024 and as our Chief Information Officer from April 2014 to February 2018. Prior to joining NGL, Ms. Kingham was the Chief Information Officer and held Information Technology (“IT”) Audit Management positions at a professional advisory firm for nine years. Additionally, Ms. Kingham spent nine years of her career at Williams in various IT technical and successive management positions. 88 Shawn W. Coady . Dr. Coady served as our President and Chief Operating Officer, Retail Division, from April 2012 to March 2018, when we sold a portion of our Retail Propane segment to DCC LPG (“DCC”), and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady served as an executive officer of DCC from April 2018 until his retirement in December 2020. Dr. Coady served as a member of the board of directors of our GP since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), from March 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicksgas LLC, and the membership interests in Hicksgas LLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until the membership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National Propane Gas Association from 2004 to 2015 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015. Dr. Coady brings valuable operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in industry associations. James M. Collingsworth . Mr. Collingsworth has served on the board of directors of our GP since January 2015. Mr. Collingsworth previously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through January 2014. Prior to that, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior to joining Texaco, Mr. Collingsworth was director of feedstocks for Rexene Petrochemical Company from 1988 to 1991 and served in the MAPCO, Inc. organization from 1973 to 1988 in various capacities, including customer service and business development manager of the Mid-America and Seminole pipelines. Mr. Collingsworth served as a director of American Ethane Co. Mr. Collingsworth currently serves on the board of directors of Martin Midstream Partners L.P. Mr. Collingsworth brings a wealth of in-depth industry experience to the board. Mr. Collingsworth has worked in all facet