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

•political and economic conditions in oil producing regions, including the Middle East, Africa, South America, including Venezuela, and Russia;

•global geopolitical conflict,conflicts and developments, including the ongoing warconflict in Ukraine, conflicthostilities in the Middle EastEast, the evolving situation in Venezuela and the relationships between the United States and other countries, such as China and Russia;

3 Low prices for WTI and Henry Hub were in 20202021 and 2024, respectively. Excludes the period in April 2020 when WTI briefly traded in negative territory.

During the ten years prior to December 31, 2024,2025, WTI market prices at Cushing, Oklahoma have ranged from a high of $123.64 per Bbl in 2022 to a low of $8.91 per Bbl in 2020. On December 31, 2024,2025, the last trading day of 2024,2025, the WTI spot market price of oil was $72.44.$57.26. The changes in the price of oil have been caused by many factors, including periods of increasing U.S. oil production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, actions taken by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+"), and fluctuationsgeopolitical inconflicts demandand as a result of the COVID-19 pandemic.developments. If prices for oil are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our Credit Facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.

During the ten years prior to December 31, 2024,2025, natural gas prices at Henry Hub have ranged from a high of $23.86 per MMBtu in 2021 to a low of $1.21 per MMBtu in 2024. On December 31, 2024,2025, the last trading day of 2024,2025, the Henry Hub spot market price of natural gas was $3.40$4.00 per MMBtu. The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S. natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, and rising levels of U.S. natural gas exports. If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for natural gas may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our Credit Facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.

New tradeTrade policies, such as tariffs, could adversely affect our operations, costs, and business

There is currently significant uncertainty regarding the future relationship between the United States and various other countries arising from changes that may be implemented by the new presidential administration, including with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Any actions taken by the United States’ federal government that restrict or otherwise impact the economics of trade—including tariffs, trade barriers, or other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly. These developments, or the perception that more of them could occur, may materially adversely affect the global economy and stability of global financial markets, potentially reducing trade and depressing economic activity. Such changes in international trade policies may result in direct impact to our business or that of our operators through increased costs, changes in business prospects or operating results, which could adversely affect our financial condition. The extent of such impacts cannot be predicted at this time.

•unanticipated geographic or environmental constraints in the Shelby Trough; or

•delay or cancellation of construction or operation of LNG export facilities in the Gulf of Mexico.Mexico; or

Our Credit Facility limits the amounts we can borrow to a borrowing base amount, as determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amount could be decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, decreases in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2024,2025, we had $25.0$154.0 million outstanding borrowings and the aggregate maximum credit amounts of the lenders were $1.0 billion. TheIn lendersOctober under2025, ourwe amended the Credit Facility reaffirmedto ourextend the maturity date from October 31, 2027 to October 31, 2030 and remove the adjustment applied to secured overnight financing rate ("SOFR") loans. Concurrent with the Credit Facility amendment, the borrowing base inunder Novemberthe 2024Credit Facility was reaffirmed at $580.0 million and we elected to maintain cash commitments under the Credit Facility at $375.0 million. The next semi-annual redetermination is scheduled for April 2025.2026. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our Credit Facility, or sell assets, debt, or equity. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our Credit Facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.

In the past, we have made substantial capital expenditures in connection with the acquisition of mineral and royalty interests and, to a lesser extent, participation in our non-operated working interests. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, executed farmout agreements, and the issuance of equity securities.

•an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and

Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the general trend of more expansive and stricter environmental legislation and regulations will continue. Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could adversely affect the amount of cash available for distribution to our unitholders.

Increased attention to, and sometimes conflicting social expectations on, companies to address climate change and other environmental and social impacts,change, investor and societal expectations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our unit price and access to capital markets. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us.us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation or contribution to the asserted damage, or other mitigating factors. Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for additional information on related developments that may affect us, our operators, and/or the oil and gas sector more generally.

Any new laws or regulations imposing requirements on our business related to the disclosure of climate-related risks may result in reputational harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations of requirements of financial institutions. InFor March 2024, the U.S. Securities and Exchange Commission (“SEC”) finalized rules establishing a framework for the reporting of climate risks, targets, and metrics. However, the implementation of the rule has been stayed pending the outcome of legal challenges. Moreover, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda requested that the U.S. Court of Appeals for the Eighth Circuit not schedule arguments in the case while the SEC reconsiders the finalized rules. While the SEC, under the new presidential administration, may seek to repeal or otherwise modify the rules, we cannot predict whether such action will occur or its timings. Relatedly,example, California has enacted laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. Other states are expected to follow. Non-compliance with these lawslaws, to the extent applicable, may result in the imposition of substantial fines or penalties.

Relatedly,In addition, certain organizations that provide informationinformation, ratings or proxy advisory services to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings or recommendations are used by some investors to inform their investment and voting decisions. While such ratings or recommendations do not impact all investors’ investment or voting decisions, unfavorable ESG ratings or recommendations may lead to negative investor sentiment toward us and to the diversion of investment which could have a negative impact on our unit price and/or our access to and costs of capital. Additionally, institutionalcertain lendersfinancial institutions may decide not to provide funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital.capital or the ability to complete projects.

Finally, certain employment or business practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that we face increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Consideration of ESG-related factors in our decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties and increase litigation risks from private parties and governmental authorities.

Our partnership agreement generally provides that any distributions are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units in an amount equal to 7.0% of the face amount of the preferred units per annumannum, through November 27, 2023, then adjusting on November 28, 2023 and readjusting every two years thereafter, to a rate equal to the greater of (a) the rate in effect immediately prior to the relevant readjustment and (b) the 10-year Treasury Rate as of such readjustment date plus 5.5% per annum (which rate adjusted to 9.8% effective November 28, 2023 and subjectremained tothe readjustmentsame everyat two9.8% yearsfor thereafter,November 28, 2025), and (ii) second, to the holders of common units. However, the Board could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate.rate, which is currently a maximum of 21%, and would likely pay state income tax at varying rates. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or deductionscredits would flow through to our common unitholders. Because an entity-level tax would be imposed upon us as a corporation, cash distributions to our common unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our common unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from our operations and after-tax returnreturns to our common unitholders, likely causing a substantial reduction in the value of our common units.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. Further, while unitholders of publicly traded partnerships are, subject to certain limitations, generally entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualified business income” (as further discussed below), this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025.

While the determination of a partner's "amount realized" generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury Regulations provide that the "amount realized" on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner's share of a publicly traded partnership's liabilities. For a transfer of an interest in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and future prospective non-U.S. common unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, anAn individual common unitholder is entitled to a deduction equal to 20% of his or her allocable share of our "qualified publicly traded partnership income." For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities. Although we expect most of our income to qualify for this deduction, application of these rules to income from mineral interests, such as royalty income, is not entirely clear. Our counsel has advised us that under current law our royalty income should qualify for the deduction, but no assurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction.

As of December 31, 2024,2025, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured.customer. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.

AThe substantial portionmajority of our revenue is derived from sales of oilthe production volumes attributable to our interests; however, the majority of our production is derived from natural gas.gas production. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025,2026, at 1.91.8 Tcf, or 1%2% higher than the five-year average. The EIA expects inventories will rise to 3.73.8 Tcf at the end of October 2025,2026, which would be 2%5% lowerhigher than the five-year average.

Net natural gas exports averaged 12.015.0 Bcf per day during 2024,2025, a 1%26% increase from the 20232024 average. The EIA forecasts average exports of 14.116.4 Bcf per day for the start of 2025,2026, ana 18%9% increase from 20242025 levels. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations in mid-2025.2026.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end userend-user markets. Although the growth in LNG export capacity and global shipping has increased connectivity among certain markets, transportation remains infrastructure-dependent and subject to capacity constraints, and prices may continue to vary by region.

OurWe openenter into derivative contractsinstruments consistto partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contracts. Under fixed-price swap contracts,contract, a counterparty is required to make a payment to us if the settlement price is less than the swapcontract strike price.price, Conversely,and we are required to make a payment to the counterparty if the settlement price is greater than the swapcontract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of December 31, 20242025 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.

We are allowed, but not required, to hedgehedge, using swaps and collars with a term of no more than four years, up to 90% of suchour expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of December 31, 2024,2025, we had hedged 77%93% and 24%27% of our available oil and condensate hedge volumes and 82%100% and 69%54% of our available natural gas hedge volumes for 20252026 and 2026,2027, respectively.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, seismic data acquisition costs, non-cash equity-based compensation, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cashCash flowFlow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Adjusted EBITDA and Distributable cashCash flowFlow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”) in the U.S. as measures of our financial performance.

The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cashCash flowFlow for the periods indicated:

Total revenue for the year ended December 31, 20242025 decreasedincreased compared to the year ended December 31, 2023.2024. The decreaseincrease in total revenue from the corresponding period is due to lower oil and condensate sales, lowerhigher natural gas and NGL sales, higher lease bonus and other income and a lossgain on commodity derivative instruments in 20242025 compared to a gainloss in 2023.2024. Lower oil revenues, resulting from reduced production and commodity prices, partially offset the overall increase in total revenue.

Oil and condensate sales. Oil and condensate sales decreased for the year ended December 31, 20242025 as compared to the year ended December 31, 20232024 due to lower realized commodity prices and lower production volumes. The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and EaglePermian FordBasin play trends. Our mineral and royalty interest oil and condensate volumes accounted for 95%96% and 94%95% of total oil and condensate volumes for the years ended December 31, 20242025 and 2023,2024, respectively.

Natural gas and natural gas liquids sales. Natural gas and NGL sales decreasedincreased for the year ended December 31, 20242025 as compared to the year ended December 31, 20232024 due to lowerhigher realized commodity prices andpartially offset by lower production volumes. The decrease in natural gas and NGL production was driven by reduceddecreased production volumes in the Austin Chalk, Bakken/Three Forks,Chalk and Haynesville/Bossier play trends. Mineral and royalty interest production accounted for 95%96% and 94%95% of our natural gas volumes for the years ended December 31, 20242025 and 2023,2024, respectively.

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During 2024,2025, we recognized $11.0 million of realized gains and $36.6 million of unrealized gains from our commodity derivatives, compared to $45.2 million of realized gains and $50.9 million of unrealized losses from our commodity derivatives, compared to $82.7 million of realized gains and $8.4 million of unrealized gains in 2023.2024. The unrealized lossesgains on our commodity contracts in 20242025 were driven equally by changes in the forward commodity price curves for both natural gas and oil while the unrealized gainslosses in 20232024 were primarily driven by changes in the forward commodity price curves for natural gas.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus incomerevenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income was slightly lowerhigher for the year ended December 31, 2024,2025, as compared to 2023.2024. Leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin ChalkHaynesville/Bossier plays made up the majority of lease bonus and other income for 2024,2025, while the majority of our 20232024 lease bonus and other income came from leasing activity in the HaynesvilleWolfcamp, Bakken/BossierThree Forks, and WolfcampAustin plays.Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development.

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreasedincreased slightly in 20242025 as compared to 2023,2024, due to a reduction in variable costs as a result of lower production from our non-operated working interest properties and lowerhigher nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the year ended December 31, 2024,2025, production and ad valorem taxes decreased as compared to the year ended December 31, 2023,2024, primarily due to a decrease in production taxes and processing and transportation costs stemming from lower commodity prices and decreased production volumes.volumes, as well as lower ad valorem tax estimates.

Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where we are the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense was significantly higher in 20242025 as compared to 2023,2024, primarily duedriven toby anpurchases increaseof seismic data and costs from proprietary seismic projects associated with existing and future development programs in seismicthe costsexpanded andShelby delayTrough rentals.area.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during sucha period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense decreased for the year ended December 31, 20242025 as compared to 2023,2024, primarily due to lower production volumes.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2024,2025, general and administrative expenses slightly increased compared to 2023,2024, primarily due to increaseshigher insalaries salaries,of software$1.4 relatedmillion expenses,driven by increased headcount and consultinginflation, costshigher forsoftware-related internalexpenses projects;of these$1.2 costsmillion, wereand partiallyhigher offset by a decrease in equity basedequity-based compensation and expenses associated with the use of contractors.$1.2 million. The decreaseincrease in equity-based compensation was due to lowerhigher costs recognized for performance-based incentive awards resultingdriven fromby downward movementschanges in our common unit price during 20242025, compared to upward2024. movementsThese increases were partially offset by a $0.6 million decrease in ourconsulting commoncosts unitfor priceinternal during 2023.projects.

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility as applicable,Facility, and for investing in our business. On November 28, 2023 theThe distribution rate for the Series B cumulative convertible preferred units was adjusted toNovember 9.8%28, 2023 and will be readjusted every two years thereafter (each, a "Readjustment Date"). The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025. We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at para value,redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to $20.39,par withinvalue. aOn 90-dayAugust period21, 2025, we entered into an agreement with the holders of the Series B cumulative converted preferred units under which we agreed not to exercise our redemption option and the holders agreed to vote in accordance with Board recommendations and comply with customary transfer and standstill restrictions through November 27, 2027, with the next redemption window opening on each second anniversary following November 28, 2023.2027. Depending on market conditions among other factors, we may use funds from the future issuance of common units or other equity securities or debt to redeem some or all of the preferred units. See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash provided by operating activities for 20242025 decreased as compared to 2023.2024. The decrease was primarily due to areduced oil sales due to lower realized oil prices and production, and lower amounts of cash received from the settlement of commodity derivatives. The overall decrease inwas oilpartially andoffset condensateby sales revenue andhigher natural gas and NGL sales revenue,due andto ahigher decreaserealized natural gas prices in cash2025 receivedcompared onto settlementsthe ofsame commodityperiod derivativein instruments.2024.

Investing Activities. Net cash used in investing activities for 20242025 slightly increased as compared to 2023.2024. The changeincrease was primarily due to increasedhigher acquisitionadditions activityto oil and natural gas properties leasehold costs in 20242025 compared to the same period in 2023.2024.

Financing Activities. CashNet flowscash used in financing activities for 20242025 decreased as compared to 2023.2024. The decrease was primarily due to lower distributions paid to common unitholders partiallyand offsethigher byborrowings net borrowingsof repayments under our Credit Facility in 20242025 compared withto net repayments in 2023.2024.

During 20242025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $110.4$114.5 million, including capitalized direct transaction costs. The cash portion of the consideration paid consisted of $109.4$107.1 million in cash that was funded with borrowings under our Credit Facility and funds from operating activities,activities and $1.0$7.4 million in equity that was funded through the issuance of our common units based on the fair values of the common units issued on the acquisition dates. These acquisitions were considered asset acquisitions and were primarily located in theEast GulfTexas, Coast land region. Our current commercial strategy includeswithin the continuationHaynesville ofexpansion meaningful, targeted mineral and royalty acquisitions to complement our existing positions.area.

In theMarch third quarter of 2024,2025, we closed on a transaction with a third-party operator whereby we receivedacquired an oil and natural gas lease on approximately 8,0002,900 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000900 undeveloped net mineral and royalty acres in Mississippi.Louisiana.

We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027.2030. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million. The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 andWe reaffirmed the borrowing base in April 2024, November 2024 and NovemberApril 2024.2025 Afterat each$580.0 redeterminationmillion. In October 2025, we amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and remove the adjustment applied to secured overnight financing rate ("SOFR") loans. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was reaffirmed at $580.0 million and we elected to maintain cash commitments under the Credit Facility at $375.0 million. All existing banks in the lender syndicate elected to continue participating in the Credit Facility. No other significant terms were changed as part of the amendment. The next semi-annual redetermination is scheduled for April 2025.2026.

As of MarchJune 31,30, 2026, our mineral and royalty interests were located in 41 states in the continental U.S., including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

DuringAt the firstend of the second quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating threetwo rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas successfully turned to sales 4 gross (0.4 net) wells in July 2026. Adamas’s development program remains on track,track with 4the development agreements, with a total of 14 wells spud in the first quarter of 2026 as part of the currentprevious program year endingthat ended on June 30, 2026,2026. anOf additionalthese 4wells, wells6 expectedgross in(0.6 thenet) second quarter of 2026 to complete that program year, and 10 more wells expected in the second half of 2026 as part of the next program year. Adamas successfullyhave turned to sales 7as of July 31, 2026, and 8 gross (0.50.7 net) wellsare during the first quarter and expectsexpected to turn to sales 12 gross (1.2 net) wells during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.

Our agreement with Revenant Energy ("Revenant") covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres. Under the original agreement, Revenant iswas obligated to drill a minimum of 6 wells in 2026, increasing annually to a minimum of 25 wells per year by 2030. We also secured a non-operated working interest partner for the development. In November 2025, the agreement was amended to maintain the original 6-well commitment for 2026 and convert future commitments to completed gross lateral-foot targets at one well per 7,000 lateral feet, allowing longer laterals while keeping overall development levels unchanged. RevenantIn spudMay 2026, we entered into an amendment to the JEA that reduced the Program Year 1 drilling commitments to 4 wells following the well control incident in April 2026 affecting one of the two wells spud in the first quarter of 2026,2026. oneThe amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program. Development activity continued during the second quarter of which2026, experiencedwith aRevenant lossspudding oftwo welladditional control incident in April 2026. We are currently assessing the potential impact of this incident on Revenant’s first program year development program and related well commitments.wells.

In November 2025, we entered into a 220,000 gross acre development agreement with Caturus Energy, LLC ("Caturus"), which aims to push the Shelby Trough westward towards the Western Haynesville. Activity will begin with approximately 2 gross (0.2 net) wells in the second half of 2026 and ramp to approximately 12 gross (0.8 net) wells annually by 2031, supported by minimum annual lateral-foot requirements, all net to our interest. In addition to the 2 gross development wells in 2026, Caturus plansis tocurrently drilldrilling a pilot well steppingin out towards HoustonCherokee County, consistent with the terms of the agreement.

In the Permian Basin, CoterraBlue EnergyArrow continuesOperating to develop our acreageis in Culbersonprogress County,on Texas. During the first quarter, 17 gross wells (0.6 net) were turned to sales. A separatea development by another Permian operator of 25 gross (1.9 net) wells in the southern Delaware BasinBasin. isThree wells were turned to sales during the quarter with the remaining expected to come online in the second half of 2026 and first half of 2027.

In the firstsecond quarter of 2026, consistent with our previously announced acquisition strategy, we acquired $11.5$37.2 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through MarchJune 2026, we have completed $251.0$299.7 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.

Oil prices increased during the threefirst monthshalf ended March 31,of 2026 compared to the same period in 2025, primarily due to the outbreak of conflict inwith Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices decreasedwere lower during the threefirst monthshalf ended March 31,of 2026 relative to the prior-year period. Natural gas prices were elevated in January and early Februaryin 2026 due to colder-than-normalwinter weather and tighter inventories but declinedgenerally overmoderated during the remainder of the quarterfirst six months as milderproduction wintergrowth conditionsincreased acrossmarket mostsupplies. Recent price strength at the end of the second quarter was driven by rising electric power demand and increased U.S. persisted. Continued growth inliquefied natural gas production("LNG") alsoexport contributed to downward pressure on prices during the quarter.volumes.

The majority of the production volumes attributable to our interests isare derived from natural gas production. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Net natural gas exports averaged 17.517.2 Bcf per day during the firstsecond quarter of 2026, a 16%14% increase from the 2025 average. The EIA forecasts average exports of 16.817.3 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that U.S. liquefied natural gas ("LNG") exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.

The prices we receive for oil, natural gas, and natural gas liquids ("NGLs") vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All of our production is derived from properties located in the U.S.

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of MarchJune 31,30, 2026 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

WeThe areCredit allowed,Facility allows but does not required,require us to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of MarchJune 31,30, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027.

Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three and six months ended MarchJune 31,30, 20252025, for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation. Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests.

Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025

Total revenue for the quarter ended MarchJune 31,30, 2026 increaseddecreased compared to the quarter ended MarchJune 31,30, 2025. The increasedecrease in total revenue in the firstsecond quarter of 2026 is primarily due to higherlower oil and condensate sales and higher natural gas and NGL sales, which were partially offset by increased lossesgains on our commodity derivative instruments and lower natural gas and NGL sales partially offset by increased oil and condensate sales as well as higher lease bonus and other income compared to the corresponding prior period.income.

Oil and condensate sales. Oil and condensate sales increased for the quarter ended MarchJune 31,30, 2026 as compared to the corresponding period in 2025 primarily due to increased production volumes, which were partially offset by slightly decreased realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty volumes in the Permian Basin and the Eagle Ford trends. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended MarchJune 31,30, 2026 and 2025.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increaseddecreased for the quarter ended MarchJune 31,30, 2026 as compared to the corresponding prior period. The increase was due to higher realized commodity pricesdecrease between the comparative periods is due to lower realized commodity prices and increasedslightly decreased production volumes. The increasedecrease in production was driven by higherlower royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for each of the quarters ended MarchJune 31,30, 2026 and 2025.2025, respectively.

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the firstsecond quarter of 2026, lossesgains from our commodity derivative instruments increaseddecreased compared to the same period in 2025. For the three months ended MarchJune 31,30, 2026, we recognized $12.2$8.8 million of realized losses and $52.3$35.6 million of unrealized lossesgains from our oil and natural gas commodity contracts, compared to $3.6$3.2 million of realized lossesgains and $52.4$49.6 million of unrealized lossesgains in the same period in 2025. The unrealized lossesgains on our commodity contracts during the firstsecond quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized lossesgains for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the firstsecond quarter of 2026 was lowerhigher than the same period in 2025. Leasing activity in the PermianHaynesville/Bossier Basin and proceeds from surface use waivers on our mineral acreage supporting solar developmentplay comprised the majority of lease bonus and other income for both the firstsecond quarter of 20262026, while the majority of lease bonus and other income in the firstsecond quarter of 2025.2025 Thecame surfacefrom useleasing waivers covered mineral acreageactivity in Mississippi for the firstPermian quarter of 2026Basin and LouisianaBakken/Three forForks the first quarter of 2025.plays.

Operating and Other Expenses

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended MarchJune 31,30, 2026 as compared to the same period in 2025, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended MarchJune 31,30, 2026, production costs and ad valorem taxes decreased compared to the quarter ended MarchJune 31,30, 2025. The decrease was primarily due to $2.3$4.2 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions, as well as lower ad valorem tax estimates.deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues and volumes.revenues.

Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. For the quarter ended MarchJune 31,30, 2026, exploration expenses decreasedincreased compared to the same period in 2025, primarily due to ahigher decreaseexpenditures for seismic costs incurred in connection with ongoing seismic costs.shoots tied to our development programs.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended MarchJune 31,30, 2026 as compared to the same period in 2025 due to higher productiondepletion volumes.rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended MarchJune 31,30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $1.1$1.2 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount.headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Interest expense. Interest expense increased for the quarter ended MarchJune 31,30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business. The Series B cumulative convertible preferred units are entitled to quarterly distributions based on an annual distribution rate (the "Distribution Rate"), which is subject to adjustment every two years (each, a "Readjustment Date") with the last Readjustment Date on November 28, 2025. The rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the Distribution Rate shall be increased by 2.0% per annum for such quarter. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date. We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day90-day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value. On August 21, 2025, we entered into an agreement with the holders of the Series B cumulative convertible preferred units under which we agreed not to exercise our redemption option and the holders agreed to vote in accordance with Board recommendations and comply with customary transfer and standstill restrictions through November 27, 2027, with the next redemption window opening on November 28, 2027. Depending on market conditions among other factors, we may use funds from the future issuance of common units or other equity securities or debt to redeem some or all of the preferred units. See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. As of MarchJune 31,30, 2026, we had not made any repurchases under the program.

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreasedincreased for the threesix months ended MarchJune 31,30, 2026 as compared to the same period of 2025. The decreaseincrease was primarily driven by higher oil sales due to increased interestrealized expenseoil prices and production volumes in the threesix months ended MarchJune 31,30, 2026,2026. thatThe resultedoverall fromincrease was partially offset by higher averagecash outstandingpaid borrowingsfor underthe oursettlement Creditof Facility.commodity derivatives.

FinancingInvesting Activities. Net cash used in financinginvesting activities decreased forin the threesix months ended MarchJune 31,30, 2026 increased as compared to the same period of 2025. The decreaseincrease was primarily driven by lower distributions paiddue to commonhigher unitholdersexpenditures for acquisitions of oil and natural gas properties and leasehold costs in the threesix months ended MarchJune 31,30, 2026,2026 compared to the same period of 2025. The overall decrease was partially offset by lower net borrowings under our Credit Facility.

Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.2$0.3 million during the threesix months ended MarchJune 31,30, 2026. We have also spent $0.2$6.3 million to acquire leases in areas around our drilling programs during the threesix months ended MarchJune 31,30, 2026.

During the threesix months ended MarchJune 31,30, 2026, we acquired mineral and royalty interests that consisted primarily of primarily unproved oil and natural gas properties in East Texas from various sellers for cashan considerationaggregate of $11.5$48.7 million, including capitalized direct transaction costs. The consideration paid consisted of $45.9 million in cash that was funded fromwith borrowings under our Credit Facility and funds from operating activities.activities, and $2.8 million in equity, that was funded through the issuance of common units based on the fair value of the common units issued on the acquisition dates. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

Adamas expects to drilldrilled a total of 14 wells induring the current program year,year endingthat ended on June 30, 2026,2026 and applyapplied 2 of its 10 banked wells toward its commitment. As of MarchJuly 31, 2026, Adamas8 of those wells had spudnot 10yet turned to sales and are expected to begin production during the remainder of 2026. Adamas expects to drill 17 wells in the currentnext program year andthat hadbegan ain totalJuly of 10 banked wells.2026.

In May 2025, we entered into a JEA with Revenant covering an expanded portion of our Shelby Trough acreage, primarily located in Angelina, Nacogdoches, and San Augustine counties in Texas. The agreement grants Revenant exclusive development rights across three designated areas of interest ("AOIs") and requires minimum annual drilling commitments that escalate over a five-year period, including test wells in certain areas, to maintain development rights across the full contract area. The agreement allows for non-operated working interest participation, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our retained undivided 35% working interest.

The table below summarizes the minimum gross lateral-foot drilling commitments under the amended agreement, including both AOI-specific and contract-wide commitments, following Program Year 1:

We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of MarchJune 31,30, 2026, we were in compliance with all debt covenants.

As of MarchJune 31,30, 2026, there have been no material changes to our material cash requirements previously disclosed in our 2025 Annual Report on Form 10-K.

As of MarchJune 31,30, 2026, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2025 Annual Report on Form 10-K.