NYSE: NGL-PB

•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, access to 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.

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, have allowed us to focus on moving to becoming a pure play water solutions company and have improved our overall financial position. As part of these actions, we completed the below dispositions during the current fiscal year:

•On April 14, 2025, we sold certain investments in unconsolidated entities, property, plant and equipment and intangible assets in our Water Solutions segment;

•On April 30, 2025, we sold our refined products business, which was part of our Liquids Logistics segment, including certain working capital items; and

•On April 30, 2025, we sold most of our wholesale propane business, 17 of our natural gas liquids terminals, our interest in an unconsolidated entity and working capital (“Wholesale Propane Disposition”), which was part of our Liquids Logistics segment.

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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 disposition transactions and the impact to our operations, see Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and 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, 2025 and 2024.

Debt Refinancing

On March 12, 2026, we closed a debt refinancing transaction of $950.0 million consisting of a new seven-year senior secured 2026 term loan “B” credit facility (“2026 Term Loan B”).

In connection with the closing of the debt refinancing transaction, our asset-based revolving credit facility (“ABL Facility”) was amended to reduce our total commitments and to make other changes to the terms thereof.

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

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Primary Service Areas

The following map shows the primary service areas of our businesses at May 28, 2026:

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Organizational Chart

The following chart provides a summarized overview of our legal entity structure at May 28, 2026:

(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.

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Our Business Strategies

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

•Position the Partnership as a leading pure play produced water infrastructure platform providing water solutions to upstream customers. We currently operate the largest integrated produced water pipeline, disposal, and water handling network in the Delaware Basin, supported by long-term, fee-based producer contracts and continue to enhance our ability to transport produced water from the wellhead to treatment for disposal, recycle, or discharge through our expanding pipeline infrastructure and ongoing disposal capacity investments. While maintaining complementary crude oil and natural gas liquids logistics operations, capital allocation and strategic focus are centered on providing water solutions services, which will reduce earnings volatility and enhance cash flow stability.

•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 eliminate our Class D Preferred Units (“Class D Preferred Units”) and reduce 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.

•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, a significant portion 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 with acreage dedications with producers, refiners and marketers and which include minimum volume commitments on our storage tanks and owned and leased pipelines.

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•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 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 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 washouts. Our activities in this segment are underpinned by long-term, fixed fee contracts and acreage dedications, a significant portion 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 1.063 billion barrels of produced water across its areas of operation during the year ended March 31, 2026, 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 approximately 840 miles of newly-built, in-service large diameter produced water pipelines connected to 59 active saltwater disposal facilities and 141 active disposal wells. We currently have approximately 766,000 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 significant 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 transports 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.

On May 7, 2026, we announced a further expansion of our LEX II Pipeline System to increase capacity by 165,000 barrels of water per day with a capability to transport approximately 560,000 barrels of water per day on the LEX II system.

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The LEX II Expansion is underwritten by a newly executed long-term volume commitment contract that includes increased volume commitments, and an additional four township committed area in Eddy County, New Mexico. Additionally, the LEX II Expansion is expandable up to 650,000 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, 2026, we sold approximately 72.5 million barrels of recycled water.

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, 2026, in the Delaware Basin, we received approximately 99% 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 91 water treatment and disposal facilities, including 202 injection wells. The location and permitted processing capacities of these facilities are summarized below.

Number ofNumber ofPermitted Processing Capacity (barrels per day)

LocationFacilities (1)WellsOwn (2)Lease (3)Total

Delaware Basin (4) - Texas and New Mexico59 141 1,479,000 3,942,300 5,421,300

Eagle Ford Basin (4)(5) - Texas18 30 424,000 332,000 756,000

DJ Basin - Colorado13 30 378,000 142,500 520,500

Other Basins - Texas1 1 20,000 — 20,000

Total - All Facilities91 202 2,301,000 4,416,800 6,717,800

(1) We own the land on which 39 of the 91 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.

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 Water Solutions segment.

Customers. Our primary customers 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, 2026, 78% 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 dedicated acreage with us; and (c) produced water pipeline and trucked disposal agreements providing interruptible service in

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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 and recycle 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 Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas and the United States Gulf Coast.

Our foundational asset in this segment is the Grand Mesa Pipeline, 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, 2026, approximately 72,000 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.

We currently transport crude oil on the Grand Mesa Pipeline, which is described above, and 19 other common carrier pipelines owned by third parties.

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We also own 25 pipeline injection stations, the locations of which are summarized below.

StateNumber of Pipeline Injection Stations

Texas11

New Mexico6

Oklahoma5

Kansas3

Total25

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, 2026, 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 72 producers at 423 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.

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, access to 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

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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, 2026, we sold approximately 1.2 billion gallons of natural gas liquids or 3.17 million gallons 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)

LocationNumber of FacilitiesOwn (1)Lease (2)TotalTerminal Interconnects

Virginia2 20,888,000 — 20,888,000 Rail, Truck and Marine Facility

Louisiana1 720,000 — 720,000 Truck Facility

Michigan1 480,000 — 480,000 Truck and Pipeline Facility

Washington1 — 120,000 120,000 Rail and Truck Facility

Total5 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 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

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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 29 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 3,600 high-pressure and general purpose leased railcars of which 123 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 LocationBeginning

April 1,

2026At

March 31,

2026Storage Interconnects

Michigan10,500,000 10,500,000 Rail and Truck Facility

Mississippi8,400,000 8,400,000 Pipeline and Rail Facility

Texas210,000 210,000 Pipeline and Rail Facility

Utah— 5,880,000 Rail Facility

United States Total19,110,000 24,990,000

Alberta, Canada1,323,420 1,323,420 Pipeline and Rail Facility

Canada Total1,323,420 1,323,420

Total20,433,420 26,313,420

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, 2026, 45% 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.

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;

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•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, 2026, we had 449 employees in 14 states and Canada. Of those employees, 214 provide work primarily for our Water Solutions segment, 55 provide work primarily for our Crude Oil Logistics segment, 60 provide work primarily for our Liquids Logistics segment, and 120 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 97% of our eligible employees participated in the NGL 401(k) Plan in fiscal year 2026. 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:

• 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.

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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.

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,

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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.

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

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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 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

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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 (“DOI”), 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 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

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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). These bills are currently subject to various legal challenges, and the outcomes of those challenges are uncertain. In November 2025, the U.S. Court of Appeals for the Ninth Circuit granted a motion for injunction as to the enforcement of SB 261; however, a similar motion for injunction as to the enforcement of SB 253 was denied, meaning SB 253 and its initial reporting deadline in August 2026 currently remain unaffected. Additionally, the New York State Department of Environmental Conservation established a mandatory GHG reporting program that requires certain emitters of GHG emission sources to annually report their emissions and related data. These mandates could affect our business, and they are being routinely evaluated to determine applicability and relevant requirements.

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. In September 2025, the Eighth Circuit indicated that the case will be held in abeyance until such time that the SEC decides to reconsider the challenged rules by notice-and-comment rulemaking or renews its defense.

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

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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.

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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.