Black Stone Minerals, L.P. 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto presented elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2025 and 2024. For the discussion of changes from 2024 to 2023 and other financial information related to 2023, refer to Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2025. Overview As of December 31, 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. 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. Recent Developments Development Activity During the fourth quarter, Aethon was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. Aethon’s development program remains on track, with 6 wells spud in the second half of 2025 as part of the current program year ending June 30, 2026, an additional 8 wells expected in the first half 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. Aethon successfully turned to sales 7 gross (0.42 net) wells during the fourth quarter and has an inventory of 5 gross (0.31 net) wells from the previous program year that it expects to turn to sales during early 2026. Our agreement with Revenant covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres. Revenant is 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 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. Revenant expects to spud more wells than its 6-well commitment for the first program year ending December 31, 2026. In November 2025, we entered into a 220,000 gross acre development agreement with 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 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 wells in 2026, Caturus plans to drill a pilot well stepping out towards Houston County, consistent with the terms of the agreement. For additional information about our Shelby Trough development agreements, please read Part I, Items 1. and 2. “Business and Properties—Our Assets—Shelby Trough Development Agreements”. In the Permian Basin, Coterra Energy continues to develop our acreage in Culberson County, Texas. During the third quarter, 5 gross wells (0.17 net) were turned to sales, with the remaining 34 gross (1.21 net) wells expected in the first half of 2026. A second large development of 30 gross (2.04 net) wells in the southern Delaware Basin is expected to come online in the second half of 2026 and first half of 2027. 48 Acquisition Activity In the fourth quarter of 2025, we acquired $48.8 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through December 2025, we have completed $239.5 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area. Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. Commodity Prices and Demand 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. Oil prices decreased during the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased global supply and uncertainty about the outlook for global economic growth and oil demand. Supply growth from both OPEC+ and non-OPEC+ producers contributed to higher global inventories during the year, placing downward pressure on crude oil prices. Natural gas prices increased during the year ended December 31, 2025 relative to the prior-year period. Colder-than-normal weather during the first quarter increased heating demand and reduced storage levels, while higher demand for power generation during the summer months also contributed to higher natural gas prices. In addition, continued growth in LNG export demand further strengthened market conditions. In the fourth quarter of 2025, natural gas prices rose, driven by seasonal heating demand, continued LNG export demand, and relatively tight storage levels. Given the dynamic nature of commodity markets, we cannot reasonably estimate how long current price levels or market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. The following table reflects commodity prices at the end of each quarter presented: 2025 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 57.26 $ 63.17 $ 66.30 $ 71.87 Henry Hub spot natural gas ($/MMBtu) 1 $ 4.00 $ 3.12 $ 3.26 $ 4.11 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The following table shows the rig count at the end of each quarter presented: 2025 U.S. Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 412 424 432 484 Natural gas 125 117 109 103 Other 9 8 6 5 Total 546 549 547 592 1 Source: Baker Hughes Incorporated 49 Natural Gas Storage The majority of the production volumes attributable to our interests is 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. 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 withdraw al season, which is the end of March 2026, at 1.8 Tcf, or 2% higher than the five-year average. The EIA expects inventories will rise to 3.8 Tcf at the end of October 2026, which would be 5% higher than the five-year average. The following table shows natural gas storage volumes by region at the end of each quarter presented: 2025 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 736 832 602 284 Midwest 865 972 688 364 Mountain 264 269 228 165 Pacific 307 302 287 202 South Central 1,203 1,186 1,148 758 Total 3,375 3,561 2,953 1,773 1 Source: EIA Natural Gas Exports Net natural gas exports avera ged 15.0 Bcf per day during 2025, a 26% incr ea se from the 2024 average. The EIA forecasts average exports of 16.4 Bcf per day for the start of 2026, a 9% increase from 2025 levels. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations in 2026. 50 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following: • volumes of oil and natural gas produced; • commodity prices including the effect of derivative instruments; and • Adjusted EBITDA and Distributable Cash Flow. Volumes of Oil and Natural Gas Produced In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances. Commodity Prices Factors Affecting the Sales Price of Oil and Natural Gas The prices we receive for oil, natural gas, and 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 NYMEX prices are referred to as differentials. All our production is derived from properties located in the United States. • Oil . The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points. • Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. 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-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. 51 Hedging 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 December 31, 2025 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months. We are allowed, but not required, 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 December 31, 2025, we had hedged 93% and 27% of our available oil and condensate hedge volumes and 100% and 54% of our available natural gas hedge volumes for 2026 and 2027, respectively. We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production. We do not enter into derivative instruments for speculative purposes. Non-GAAP Financial Measures Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis. 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, and gains and losses on sales of assets, if any. We define Distributable Cash Flow 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. 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 year ended December 31, 2024 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. Adjusted EBITDA and Distributable Cash Flow 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. 52 Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable Cash Flow may differ from computations of similarly titled measures of other companies. 53 The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated: Year Ended December 31, 2025 2024 (in thousands) Net income $ 299,932 $ 271,326 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 36,887 45,196 Interest expense 8,930 3,109 Income tax expense (benefit) (137) 509 Accretion of asset retirement obligations 1,374 1,298 Seismic data acquisition costs 17,349 2,287 Equity-based compensation 9,620 8,564 Unrealized (gain) loss on commodity derivative instruments (36,602) 50,944 Adjusted EBITDA 337,353 383,233 Adjustments to reconcile to Distributable Cash Flow: Change in deferred revenue (3) (4) Cash interest expense (7,845) (2,030) Preferred unit distributions (29,466) (29,466) Distributable Cash Flow $ 300,039 $ 351,733 54 Results of Operations Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2025 2024 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,259 3,606 (347) (9.6) % Natural gas (MMcf) 1 56,237 62,984 (6,747) (10.7) % Equivalents (MBoe) 12,632 14,103 (1,471) (10.4) % Equivalents/day (MBoe) 34.6 38.5 (3.9) (10.1) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 64.24 $ 74.61 $ (10.37) (13.9) % Natural gas ($/Mcf) 1 3.41 2.51 0.90 35.9 % Equivalents ($/Boe) $ 31.74 $ 30.27 $ 1.47 4.9 % Revenue: Oil and condensate sales $ 209,361 $ 269,061 $ (59,700) (22.2) % Natural gas and natural gas liquids sales 1 191,616 157,907 33,709 21.3 % Lease bonus and other income 21,351 12,461 8,890 71.3 % Revenue from contracts with customers 422,328 439,429 (17,101) (3.9) % Gain (loss) on commodity derivative instruments 47,591 (5,730) 53,321 (930.6) % Total revenue $ 469,919 $ 433,699 $ 36,220 8.4 % Operating expenses: Lease operating expense $ 10,141 $ 9,705 $ 436 4.5 % Production costs and ad valorem taxes 39,024 49,577 (10,553) (21.3) % Exploration expense 18,634 2,735 15,899 581.3 % Depreciation, depletion, and amortization 36,887 45,196 (8,309) (18.4) % General and administrative 55,463 52,082 3,381 6.5 % Other expense: Interest expense $ 8,930 $ 3,109 $ 5,821 187.2 % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas. Revenue Total revenue for the year ended December 31, 2025 increased compared to the year ended December 31, 2024. The increase in total revenue from the corresponding period is due to higher natural gas and NGL sales, higher lease bonus and other income and a gain on commodity derivative instruments in 2025 compared to a loss in 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, 2025 as compared to the year ended December 31, 2024 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 Permian Basin play trends. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for the years ended December 31, 2025 and 2024, respectively. 55 Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to higher realized commodity prices partially offset by lower production volumes. The decrease in natural gas and NGL production was driven by decreased production volumes in the Austin Chalk and Haynesville/Bossier play trends. Mineral and royalty interest production accounted for 96% and 95% of our natural gas volumes for the years ended December 31, 2025 and 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 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 in 2024. The unrealized gains on our commodity contracts in 2025 were driven equally by changes in the forward commodity price curves for both natural gas and oil while the unrealized losses in 2024 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 was higher for the year ended December 31, 2025, as compared to 2024. Leasing activity in the Wolfcamp, Bakken/Three Forks, and Haynesville/Bossier plays made up the majority of lease bonus and other income for 2025, while the majority of our 2024 lease bonus and other income came from leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development. Operating 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 increased slightly in 2025 as compared to 2024, due to higher 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, 2025, production and ad valorem taxes decreased as compared to the year ended December 31, 2024, primarily due to a decrease in production taxes and processing and transportation costs stemming from decreased production 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 2025 as compared to 2024, primarily driven by purchases of seismic data and costs from proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough 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 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 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, 2025 as compared to 2024, primarily due to lower production volumes. 56 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, 2025, general and administrative expenses slightly increased compared to 2024, primarily due to higher salaries of $1.4 million driven by increased headcount and inflation, higher software-related expenses of $1.2 million, and higher equity-based compensation of $1.2 million. The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards driven by changes in our common unit price during 2025, compared to 2024. These increases were partially offset by a $0.6 million decrease in consulting costs for internal projects. Other Expense Interest expense. For the year ended December 31, 2025, interest expense increased compared to 2024, primarily due to higher average outstanding borrowings under our Credit Facility. 57 Liquidity and Capital Resources Overview 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 distribution rate for the Series B cumulative convertible preferred units adjusted November 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 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 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 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 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. The Board has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions on our common units quarterly or on any other basis, and there is no guarantee that we will pay distributions to our common unitholders in any quarter. The Board may change the foregoing distribution policy at any time and from time to time. 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 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. 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 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. As of December 31, 2025, we had not made any repurchases under the program. Cash Flows Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 The following table shows our cash flows for the periods presented: Year Ended December 31, 2025 2024 Change (in thousands) Cash flows provided by operating activities $ 310,167 $ 389,043 $ (78,876) Cash flows used in investing activities (118,274) (112,236) (6,038) Cash flows used in financing activities (192,934) (344,570) 151,636 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 2025 decreased as compared to 2024. The decrease was primarily due to reduced 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 was partially offset by higher natural gas and NGL sales due to higher realized natural gas prices in 2025 compared to the same period in 2024. 58 Investing Activities . Net cash used in investing activities for 2025 slightly increased as compared to 2024. The increase was primarily due to higher additions to oil and natural gas properties leasehold costs in 2025 compared to the same period in 2024. Financing Activities . Net cash used in financing activities for 2025 decreased as compared to 2024. The decrease was primarily due to lower distributions paid to unitholders and higher borrowings net of repayments under our Credit Facility in 2025 compared to 2024. Development Capital Expenditures In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created based upon our estimate of internally generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part, based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing, size, and nature of acquisitions are unpredictable. Expenditures related to drilling, completion, and recompletion costs for our non-operated working interests were $0.6 million and $0.8 million during 2025 and 2024, respectively. Additionally, we spent $11.1 million and $3.4 million acquiring leases in areas around our drilling programs during 2025 and 2024, respectively. Acquisitions Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions. During 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $114.5 million, including capitalized direct transaction costs. The consideration paid consisted of $107.1 million in cash that was funded from operating activities and $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 East Texas, within the Haynesville expansion area. During 2024 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 million, including capitalized direct transaction costs. The cash portion of the consideration paid of $109.4 million was funded with borrowings under our Credit Facility and funds from operating activities, and $1.0 million 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 East Texas, within the Haynesville expansion area. See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information. Asset Exchange We completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas. These transactions, which are described below, involved partial dispositions of unproved property, and no gains or losses were recognized. In March 2025, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana. In February 2025, we closed on a transaction with a third-party operator whereby we exchanged oil and natural gas leases covering certain acreage in East Texas. We acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres. In July 2024, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi. 59 Credit Facility 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, 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. We reaffirmed the borrowing base in April 2024, November 2024 and April 2025 at $580.0 million. 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 2026. 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 December 31, 2025, we were in compliance with all debt covenants. See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information. Material Cash Requirements Our material cash requirements consist primarily of production costs and ad valorem taxes, general and administrative expenses, including payroll and benefits, office lease commitments, settlements under our commodity derivative contracts, and lease operating expenses and asset retirement obligations associated with our non-operated working interests. We cannot provide specific timing for repayments of borrowings or associated interest under our Credit Facility, as such amounts depend on working capital requirements, commodity prices, and acquisition and divestiture activity. Similarly, the timing and amount of other obligations, including asset retirement obligations and settlements under commodity derivative contracts, cannot be forecasted with certainty. The fair value of our derivative contracts as of December 31, 2025 reflects the estimated cash settlement amount required to terminate such instruments based on forward commodity price curves as of that date. See "Note 6 – Fair Value Measurements" for additional information. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. We have provided expanded discussion of our more significant accounting estimates below. See "Note 2 – Summary of Significant Accounting Policies" within the consolidated financial statements included elsewhere in this Annual Report for additional information. Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates. Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of proved oil and natural gas properties, if necessary. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm. Other items 60 subject to estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards. We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could cause us to perform analyses to determine if our oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates. Oil and Natural Gas Properties We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification. The basis for grouping is a reasonable aggregation of properties with a common geographic location, which we also refer to as a depletable unit. As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $35.7 million, $44.8 million, and $45.0 million for the years ended December 31, 2025, 2024, and 2023, respectively. We evaluate impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See "Note 6 - Fair Value Measurements" for additional information. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded. We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2025 reserve report. Applying this discount results in an approximate 1% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2025 reserve report prepared by NSAI. Accrued Revenues We record revenue in the month production is delivered to the purchaser. As a non-operator, we have limited visibility into the timing of when new wells begin producing, and production statements may not be received for 30 to 90 days or more after production is delivered. As a result, a portion of revenue for each period is accrued and recorded in the line item Accrued revenue and accounts receivable on the consolidated balance sheets. 61 Accrued revenues are estimated using historical production data, adjusted for expected production declines, and projected sales prices, including applicable pricing adjustments. Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the operator. We review historical production, pricing assumptions, and the accuracy of prior accruals to ensure that the recorded amounts appropriately reflect revenues expected to be collected. New and Revised Financial Accounting Standards The effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.