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.

This Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Certain words in this Annual Report such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key risk factors that may affect our consolidated financial position and results of operations are:

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.”

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

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

As previously disclosed, on February 4, 2021, we closed on a private offering of $2.05 billion of our 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) and a new credit agreement which consisted of a $500.0 million asset-based revolving credit facility (“ABL Facility”). We used the net proceeds from the issuance to repay all outstanding

On April 13, 2022, we amended the ABL Facility to increase the commitments to $600.0 million under the accordion feature within the ABL Facility. As part of the amendment, we agreed to reduce the commitments back to $500.0 million on or before March 31, 2023. On February 16, 2023, we amended the ABL Facility to extend the maturity date of the additional $100.0 million of commitments through the remaining term of the ABL Facility.

For additional information related to the ABL Facility and 2026 Senior Secured Notes, see Note 7 to our consolidated financial statements included in this Annual Report.

The following map shows the primary service areas of our businesses at March 31, 2022:2023:

The following chart provides a summarized overview of our legal entity structure at March 31, 2022:2023:

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:

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:

We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the Midland Basin in Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 656.2849.5 million barrels of produced water across its areas of operation during the year ended March 31, 2022,2023, we believe that we are the largest independent produced water transportation and disposal company in the United States. We currently have over 660,000approximately 670,000 acres dedicated to our system under long-term agreements in the Northern Delaware Basin. In addition, we have several minimum volume commitments and other commercial agreements covering the Delaware, Midland,DJ, Eagle Ford DJ and Pinedale Anticline Basins. Our focus in building our Water Solutions business has been to secure long-term, fixed fee contracts that contain minimum volume commitments, acreage dedications or similarly strong contractual relationships with large, well-capitalized producer customers.

Our core asset in the Water Solutions segment is our system located in the Northern Delaware Basin, where we own and operate the largest integrated network of large diameter produced water pipelines, recycling facilities and disposal wells. This system spans six counties in New Mexico and Texas that represent one of the most prolific crude oil producing regions in the United States with some of the most economic hydrocarbon resources and lowest break-even economics for producers. Our system has approximately 650730 miles of newly-built, in-service large diameter produced water pipelines connected to 5857 active saltwater disposal facilities and 122125 active disposal wells. We currently have over 660,000approximately 670,000 acres dedicated to the Northern Delaware system providing a multi-decade drilling inventory and significant growth opportunity.

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

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

(1)    These facilities are located on lands we own.

(2)    These facilities are located on lands we lease.

(3)    Certain facilities can dispose of both produced water and solids such as tank bottoms, drilling fluids and drilling muds.

On March 31, 2023, we sold certain saltwater disposal assets in the Midland Basin (see Note 17 to process water to a recycle standard.our consolidated financial statements included in this Annual Report).

Our customers bring produced and flowback water generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline gathering systems and by truck. During the year ended March 31, 2022,2023, in the Delaware Basin, we received approximately 98% of produced and flowback water via pipelines. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.

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

Our foundational asset in this segment is the Grand Mesa Pipeline, (“Grand Mesa”), a 550-mile pipeline that transports crude oil from its origin in Weld County, Colorado to our terminal in Cushing, Oklahoma. The Grand Mesa Pipeline commenced operations on November 1, 2016 and has operated continuously since then. The main line portion of this pipeline is comprised of an undivided interest with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) in which we have the right to useownership of 150,000 barrels per day of capacity of the pipeline. During the year ended March 31, 2022,2023, approximately 28.427.7 million barrels (volume amounts are from both internal and external parties) of crude oil were transported on the Grand Mesa Pipeline. Operating costs associated with 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 ourthe Grand Mesa Pipeline. The Lucerne terminal has 950,000 barrels of operational tankagestorage and a 12 bay truck loading facility. The Riverside terminal has 20,000 barrels of storage and a four bay truck loading facility.

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

We own and operate a large scale crude oil terminal located in Cushing, Oklahoma with 3,626,000 barrels of storage capacity, seven off-loading lease automatic custody transfer units (“LACTs”), a full control room, on-site laboratory,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 ourthe Grand Mesa Pipeline and to TC Energy’s terminal with access to the United States Gulf Coast via Marketlink. Our terminal is situated on 200 acres and is designed to be expanded based on customer demand. Cushing is one of the most liquid crude oil trading hubs in the world and is the delivery point for the West Texas Intermediate futures contracts.

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

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

All of our 396 owned railcars and 210 leased railcars are compliant with the standards for railcars built subsequent to 2011 for the commodities they are transporting. (See Part I, Item 1 “Government Regulation”).

We also own 27 strategically located pipeline injection stations, the locations of which are summarized below.

Our profitability is impacted by forward crude oil prices. Crude oil markets can either be in contango (a condition in which forward crude oil prices are greater than spot prices) or can be in backwardation (a condition in which forward crude oil prices are lower than spot prices). Our Crude Oil Logistics segment benefits when the market is in contango, as increasing prices result in inventory value gains during the time between when we purchase the inventory and when we sell it. In addition, we are able to better utilize our storage assets when contango markets justify storing barrels. When markets are in

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

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

We purchase butane from refiners during the summer months, when refiners have a greater butane supply than they need, and sell butane to refiners during the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage to store butane for this purpose. We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee as well as sublease railcars to certain customers. Our owned and leased terminals and railcar fleet give us the opportunity to access markets throughout the United States, and to move product to locations where demand is highest. We provide transportation, storage, and throughput services to third parties at our facilities at Port Hudson, Louisiana and Chesapeake, Virginia.

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

The following table summarizes the location of our facilities and respective storage capacity and interconnects to those facilities.

(1)    These facilities are located on lands we own.

We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri arewere operated for us by a third party for a monthly fee under an operating and maintenance agreement that expires in November 2022.we terminated as of March 31, 2023. The terminal in St. Catharines, Ontario, Canada is operated by a third party under a year-to-year agreement.

We own the land on which 15 of the 2425 natural gas liquids terminals are located and we either have easements or lease the land on which the remaining terminals are located.

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

We own 2528 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

We own the Ambassador Pipeline, an approximately 225-mile propane pipeline, which runs from the Kalkaska gas plant in Kalkaska County, Michigan to a termination point near Marysville in St. Clair County, Michigan. We are currently working on aThe Marysville, Michigan connection which has an estimated completion date of Junewas completed in August 2022 and will allowthis allowed the Ambassador Pipeline to be fully operational. The Wheeler propane terminal, in central Michigan, was fully permitted and operational on February 1, 2022.is located at the mid-point of the pipeline. These assets complement our existing assets in the upper Midwest and will expand our presence in Michigan, one of the top propane markets in the United States.

We utilize a fleet of approximately 4,400 high-pressure and general purpose leased railcars of which 34145 railcars are subleased by third parties.

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

The following table summarizes our significant leased storage space at natural gas liquids and refined products storage facilities and interconnects to those facilities:

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

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

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

At March 31, 2022,2023, we had 842638 employees in 2829 states and Canada. Of those employees, 220229 provide work primarily for our Water Solutions segment, 24567 provide work primarily for our Crude Oil Logistics segment, 169167 provide work primarily for our Liquids Logistics segment, and 208175 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

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:

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.

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.

Consideration of and compliance with relevant environmental regulatory requirements has led our business activities to be more sustainable while simultaneously mitigating exposure to long and short-term environmental risk. Conversely, failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict andand/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 unlawfully released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

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

CERCLA, also known as the “Superfund” law, and similar state laws, impose liability on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. While natural gas liquids are not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as a hazardous substance. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict andand/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.

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

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

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.

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

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

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

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

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

With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.

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

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

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

The workplaces associated with our manufacturing, processing, terminal, disposal, storage and distribution facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard. In

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

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

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