NGL 10-K & 10-Q changes, risk factors and insider trading

•restrictions contained in the ABL Facility, 2026 Term Loan B and the indenture governing our $900.0 million of 8.125% senior secured notes due 2029 (“2029 Senior Secured Notes”) and $1.3 billion of 8.375% senior secured notes due 2032 (“2032 Senior Secured Notes”) (collectively, the “Indenture”);

•restrictions contained in the agreements relating to our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and Class D Preferred Units (collectively, the “Preferred Units”);

At March 31, 2025, the face amount of2026, our outstanding long-term debt was $3.0$3.3 billion. Our level of indebtedness could have important consequences to us, including the following:

Our leverage could have important consequences to our debt obligations. We will require substantial cash flow to meet our principal and interest obligations with respect to our debt obligations. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We may not have sufficient cash flow from operations and available borrowings under the ABL Facility to service our indebtedness. A significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable.

Restrictions in the ABL Facility, 2026 Term Loan B and Indenture could adversely affect our business, financial position, results of operations, and the value of our common units.

The ABL Facility, 2026 Term Loan B and Indenture limit our ability to, among other things:

The provisions of the ABL Facility, 2026 Term Loan B and Indenture may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and responding to, changes in business conditions. In addition, a failure to comply with the provisions of these agreements could result in a default or an event of default that could enable our lenders, subject to the terms and conditions, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secure our debts under our 2029 Senior Secured Notes, 2032 Senior Secured Notes, ABL Facility and 2026 Term Loan B. If the payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

At any time on or after July 2, 2027, each Class D Preferred Unitholder will have the right to require the Partnership to redeem on a date not prior to the 180th day after July 2, 2027 all or a portion of the Class D Preferred Units then held by such preferred unitholder for the then-applicable redemption price, which may be paid in cash or, at the Partnership’s election, a combination of cash and a number of common units not to exceed one-half of the aggregate then-applicable redemption price,price (which includes accumulated distributions in arrears), as more fully described in our Partnership Agreement. Furthermore, upon a Class D Change of Control (as defined in our Partnership Agreement), each Class D Preferred Unitholder will have the right to require the Partnership to redeem the Class D Preferred Units then held by such Preferred Unitholder at a price per Class D Preferred Unit equal to the applicable redemption price.price (which includes accumulated distributions in arrears). We cannot assure you that we will have sufficient cash flow, liquidity or the ability to incur indebtedness or sell assets on terms that are commercially reasonable in order to redeem the Class D Preferred Units, even if required to do so. In addition, we may seek to address the outstanding balances on the Class D Preferred Units prior to when they are required to be redeemed, which may impact our ability to service our indebtedness.

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

While we seek to minimize our exposure to third-party losses of our cash and cash equivalents, we hold our balances in several large banking institutions. Notwithstanding such allocation, we are subject to the risk of bank failure. For example, on March 10, 2023, Silicon Valley Bank (“SVB”) was unable to continue its operations and the Federal Deposit Insurance Corporation was appointed as receiver for SVB and created the National Bank of Santa Clara to hold the deposits of SVB. None of our cash and cash equivalents were held at SVB. However, ifIf the banking institutions where we hold deposits were to experience a similar failure, we could experience additional risk. Any such losslosses or limitationlimitations on our cash and cash equivalents wouldwhich could adversely affect our business.

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

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years, but most recently, in December 2023, the EPA finalized its rulemaking establishing New Source Performance Standards to reduce emissions of methane and other volatile organic compounds from new and modified sources. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. The United States withdrew from the Paris Agreement on November 4, 2020, and although former President Biden signed executive orders on January 20, 2021 recommitting the United States to the agreement and calling on the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement, onOn January 20, 2025, President Trump issued an Executive Order for the United States to again withdraw from the Paris Agreement. Such withdrawal is expected to taketook effect inon January 27, 2026.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates recently elected to public office. These have included promises to limit emissions and curtail the production of oil and gas, such as through the cessation of leasing public land for hydrocarbon development. For example, on January 27, 2021, former President Biden issued an Executive Order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Separately, on January 20, 2021, the Acting Secretary of the United States Department of the Interior (“DOI”) issued an order that, among other things, imposed a 60-day moratorium on the issuance of fossil fuel authorizations, including leases and permits, on federal lands. While the DOI announced on April 15, 2022 that it will resume oil and gas leasing on public lands following a federal court’s decision, theThe topic of oil and gas leasing on public land remains politically fraught,volatile asin the announcementUnited indicates that federal land available for oil and gas leasing will be reduced by 80 percent from the acreage originally nominated due to environmental and climate concerns. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas export facilities.States. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer production laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.

Hydraulic fracturing is a common practice within the oil and gas exploration and production process, including within those fields where our Water Solutions and Crude Oil Logistics segments operate. The practice of hydraulic fracturing is a well-stimulation technique utilized to facilitate the production of oil and natural gas and other hydrocarbon condensates from shale and tight conventional formations. The exploration and production process, including the practice of hydraulic fracturing, is subject to regulation by state and federal authorities. Jurisdiction and applicable regulatory requirements can vary depending on the location of the activity. At the state level, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent disclosure, permitting, or well-construction requirements on hydraulic fracturing operations, and states could elect to prohibit high-volume hydraulic fracturing altogether. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular. The process of hydraulic fracturing has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that the practice could be responsible for incidents of induced seismicity and that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may adversely impact the oil and gas drilling industry. Any current or proposed restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability. For example, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal lands, and on January 27, 2021, the DOI acting pursuant to an Executive Order from former President Biden suspended the federal oil and gas leasing program indefinitely. Although the DOI announced the resumption of onshore oil and gas leasing in April 2022, the program is being significantly reformed, with 80 percent less land available for leasing from the acreage originally nominated. On April 12, 2024, the DOI finalized a comprehensive update to federal onshore oil and gas leasing regulations on Bureau of Land Management-managed public lands, which increased bonding requirements, royalty rates, and minimum bids. Actions such as these could have a material adverse effect on us and our industry.

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21% (changed from 35% under the Tax Cuts and Jobs Act of 2017 (“Act”)), and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the market value of our common units.

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our business during our taxable year. However, under the Act signed into law by President Trump on December 22, 2017, beginning in tax year 2018, the deductibility of net interest expense is limited to 30% of our adjusted taxable income. For tax years beginning after December 31, 2017 and before January 1, 2022, the Act calculates2024, adjusted taxable income is computed using an EBITDA-based calculation. For tax years beginning January 1, 2022 and thereafter, the calculation of adjusted taxable income will not add back depreciation or amortization. Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level. These limitations might cause interest expense to be deducted by our unitholders in a later period than recognized in the GAAP financial statements.

Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, certain Treasury Regulations, which are effective for our taxable years beginning on or after January 1, 2020, provide that a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified publicly traded partnership income. As a result, income attributable to a guaranteed payment for the use of capital recognized by holders of Preferred Units is not eligible for the 20% deduction for qualified publicly traded partnership income. All holders of our Preferred Units are urged to consult a tax advisor to determine whether they are eligible to receive the 20% deduction for qualified publicly traded partnership income with respect to their Preferred Units. Further, while unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of qualified publicly traded partnership income, this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025.

TheA future global andpublic U.S.health economycrisis hascould generallylead recoveredto frominterruptions the negative economic impacts of the COVID-19 pandemic, which disruptedin global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial and commodity markets. While the World Health Organization declared an end to the global public health emergency for COVID-19 in May 2023, a future global public health crisis could lead to similar disruptionsmarkets and related economic repercussions. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for hydrocarbons that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

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

NGL Energy Partners LP,LP is a Delaware master limited partnership (“we,” “us,” “our,” or the “Partnership”), is a diversified midstream energy partnership that transports, treats, recycles and disposes of produced and flowback water generated as part of the energy production process as well as transports, stores, markets and provides other logistics services for crude oil and liquid hydrocarbons.. NGL Energy Holdings LLC serves as our general partner (“GP”). At March 31, 2025,2026, our operations included three segments as discussed below.

Our Water Solutions segment transports, treats, recycles and disposes of produced and flowback water generated from crude oil and natural gas production. We also sell produced water for reuse and recycle and brackish non-potable water to our producer customers to be used in their crude oil exploration and production activities. As part of processing water, we aggregate and sell recovered crude oil, also known as skim oil. We also dispose of solids such as tank bottoms, drilling fluids and drilling muds and perform other ancillary services such as truck and frac tank washouts. Our activities in this segment are underpinned by long-term, fixed fee contracts and acreage dedications, somea 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 Denver-Julesburg (“DJ”) Basin in Colorado and the Eagle Ford Basin in Texas. With a system that handled approximately 958.31.063 millionbillion barrels of produced water across its areas of operation during the year ended March 31, 2025,2026, we believe that we are the largest independent produced water transportation and disposal company in the United States.

The opportunity to generate revenue in our Water Solutions segment is driven in large part by the level of crude oil production in the areas where our facilities are located. Recently, our disposal volumes have been positively impacted by the increase in the level of crude oil production, particularly in the Delaware and Eagle FordDJ Basins, due to stablehigher crude oil prices. Lower crude oil prices provide producers with less incentive to drill and complete new wells, which results in lower production and negatively impacts our disposal volumes.

Our 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 (updated for the transactions discussed above).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.

Seasonality impacts our Liquids Logistics segment. Consequently, for our Liquids Logistics segment, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of our fiscal year. We generally borrow under ourthe asset-based revolving credit facility (“ABL Facility”) to supplement our operating cash flows during the periods in which we are building inventory (see “–Liquidity, Sources of Capital and Capital Resource Activities–General”).

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and nine months ended DecemberJune 31,30, 2025.2026. The discussion should be read in conjunction with theour unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 20252026 (“Annual Report”) filed with the Securities and Exchange Commission on May 29,28, 2025.2026.

OnAs Aprilpreviously 30,reported, 2025,the weoperations soldof our refined products business,business includingand certainbiodiesel workingbusiness capitalhave items,been toclassified aas third-partydiscontinued operations (see Note 115 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

Operating income increased $25.0$47.9 million for the three months ended DecemberJune 31,30, 2025,2026, compared with the same period in 2024,2025, primarily as a result of the following:

•Water Solutions – an increase of $52.9$53.6 million due primarily to higher water disposal revenues from an increase in produced water volumes processedprocessed, andhigher lowerrevenues derivativefrom losses,recovered partiallycrude offset by increased expenses mainly due to losses on disposal or impairment of assetsoil and higher depreciationpipeline and amortization expenserevenues;

•LiquidsCrude Oil Logistics – an increase of $24.3$5.2 million due primarily to increased gains on derivatives and lower expenses related to the Wholesale Propane Disposition, including a gainlosses on the sale,disposal of assets, partially offset by lower product margins, as discussed abovemargins; and

•Corporate and Other – aan decreaseincrease in operating losses of $5.7$3.5 million due primarily to increasedequity-based legalcompensation expenses.expense.

Segment Operating Results for the Three Months Ended DecemberJune 31,30, 20252026 and 20242025

(1) Water disposal service fees and Other revenues in the table above differ from the amounts reported in Note 10 to our unaudited condensed consolidated financial statements,statements included in this Quarterly Report, as the amounts in Note 10 are disaggregated by the performance obligations with type of contract and service provided and the timing of the transfer of goods and services, while the amount above is presented based on how management reviews performance. In the table above, revenues from reimbursements from construction projects, booster operating fees and generator rentals and pipeline revenue are included in Other revenues, while in Note 10 the amounts are included in Water disposal service fees.

(4) Total produced water barrels processed during the three months ended DecemberJune 31,30, 2026 and 2025 and 2024 were 282,525,872301,669,982 and 241,343,277,252,216,853, respectively. These amounts do not include 2,943,5046,457,258 barrels and 16,410,74916,367,740 barrels for the three months ended DecemberJune 31,30, 20252026 and 2024,2025, respectively, related to payments made by certain producers for committed volumes not delivered, as discussed further below.delivered. In addition, water pipeline revenue, which is included in Other Revenues,revenues, includes payments from a producer for 2,198,7573,597,195 and 9,938,5829,446,030 committed barrels not delivered during the three months ended DecemberJune 31,30, 20252026 and 2024,2025, respectively.

(5) Excluding payments made by certain producers for committed volumes not delivered, service fees for produced water processed ($/barrel) would have been $0.60$0.58/barrel and $0.60$0.61/barrel during the three months ended DecemberJune 31,30, 20252026 and 2024,2025, respectively.

Recovered Crude Oil Revenues. The decreaseincrease was due primarily to lowerhigher realized crude oil prices received from the sale of skim oil barrels,barrels partially offset byand an increase in skim oil barrels sold due to more skim oil recovered from receiving more produced water.

Recycled Water Revenues. Revenue from recycled water primarily includes the sale of produced water and recycled water for use in our customers’ completion activities. The increase was due primarily to higher pricing for recycled water. partially offset by lower recycled water volumes related to timing of water to be used in completions, partially offset by lower pricing for recycled water.completions.

Other Revenues. Other revenues primarily include reimbursements from construction projects, booster operating fees and generator rentals, water pipeline revenues,revenues and solids disposal revenues and brackish non-potable water revenues. The increase was due primarily to higher water pipeline revenue primarily from a new contract that began in February 2026 as well as higher reimbursements from construction projects and booster operating fees as well as higher water pipeline revenue, including payments from a producer for committed volumes not delivered, due to our expanded Lea County Express Pipeline system (“LEX II”) commencing operations during the three months ended December 31, 2024.fees.

Cost of Sales-Excluding Impact of Derivatives. The decreaseincrease was due primarily to amortization of an intangible asset and higher recycling costs, partially offset by lower costs incurred that will be reimbursed by producers for generator and fuel costs at various booster stations and lower recycling costs.stations.

Operating and General and Administrative Expenses. The decreaseincrease was due primarily to lowerhigher incentive compensationroyalty expense andfrom lowerincreased chemicalvolumes expense duerelated to purchasingcertain fewersaltwater chemicalsdisposal and using chemicals more efficiently, partially offset bywells, higher utilities expense due to increased produced water volumes processed and higher royaltyseverance expensetaxes due to volumes related to the LEXincrease IIin pipelinerevenue commencingfrom operationsrecovered andcrude increased volumes at certain other saltwater disposal wells.oil.

Depreciation and Amortization Expense. The decrease was due primarily to certain long-term assets being fully amortized, impaired or sold during the fiscal year ended March 31, 20252026 and ninethree months ended DecemberJune 31,30, 2025,2026, partially offset by depreciation of newly developed facilities and infrastructure.

Loss on Disposal or Impairment of Assets, Net. During the three months ended DecemberJune 31,30, 2025,2026, we recorded:

•a net gain of less than $0.1 million primarily related to the sale of certain assets.

During the three months ended DecemberJune 31,30, 2024,2025, we recorded:

Crude Oil Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, were primarily due to higher commodity prices during the three months ended June 30, 2026 and higher production on acreage dedicated to us in the DJ Basin during the three months ended DecemberJune 31,30, 2025,2026, compared to the three months ended DecemberJune 31,30, 2024, partially offset by lower commodity prices.2025.

During the three months ended DecemberJune 31,30, 2025,2026, the crude oil product margin increasedand margin per barrel decreased compared to the three months ended DecemberJune 31,30, 20242025 due to selling higher priced inventory into a declining market and due to the expiration of a crude oil barrelspurchase soldagreement during the current quarter. Product margin per barrel decreased primarily due to lower price and quality differentials realized. There was alsowith a decreasecertain in commodity pricesproducer during the three months ended DecemberMarch 31, 2025, thus also contributing to a smaller margin per barrel for the quarter.2026. Crude oil product margin calculations do not include gains and losses from derivatives that may offset the movement in the physical margin.

Crude Oil Transportation and Other Sales. The decrease was primarily due to lower pipeline revenue becauseresulting offrom the expiration of certain transportation services contracts on third-party pipelines and lower rental revenue due to the sale of our railcars.

During the three months ended DecemberJune 31,30, 2025,2026, physical volumes on the Grand Mesa Pipeline averaged approximately 85,00074,000 barrels per day, compared to approximately 61,00055,000 barrels per day during the three months ended DecemberJune 31,30, 2024.2025. Higher contracted volumes were shipped on the Grand Mesa Pipeline due to higher production on acreage dedicated to us in the DJ Basin.

Operating and General and Administrative Expenses. Operating and general and administrative expenses during the three months ended DecemberJune 31,30, 20252026 were consistent with the three months ended DecemberJune 31,30, 2024.2025.

LossDepreciation onand DisposalAmortization orExpense. ImpairmentThe ofincrease Assets, Net. Duringduring the three months ended DecemberJune 31,30, 2025,2026 we recorded a loss of $0.2 millionwas primarily due to disposal or retirementdepreciation of certainrecently assets.completed capital projects.

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The decreasesincrease in sales and cost of sales, excluding the impact of derivatives, during the three months ended DecemberJune 31,30, 2025,2026, compared to the three months ended DecemberJune 31,30, 20242025 were due primarily due to lowerhigher butane prices and volumes during the three months ended DecemberJune 31,30, 2025,2026, compared to the three months ended DecemberJune 31,30, 2024.2025.