The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025 ("2025 Annual Report on Form 10-K"). 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 II, Item 1A. Risk Factors.” Cautionary Note Regarding Forward-Looking Statements Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below: •our ability to execute our business strategies; •the volatility of realized oil and natural gas prices; •the level of production on our properties; •the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production; •our ability to replace our oil and natural gas reserves; •general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets; •competition in the oil and natural gas industry; •the level of drilling activity by our operators particularly in areas such as the Shelby Trough and Haynesville where we have concentrated acreage positions; •the ability of our operators to obtain capital or financing needed for development and exploration operations; •title defects in the properties in which we invest; •the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel; •restrictions on the use of water for hydraulic fracturing; •the availability of pipeline capacity and transportation facilities; •the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals; •federal and state legislative and regulatory initiatives relating to hydraulic fracturing; 17 •domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products and energy-related products; •future operating results; •future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions; •exploration and development drilling prospects, inventories, projects, and programs; •operating hazards faced by our operators; •the ability of our operators to keep pace with technological advancements; •conservation measures and general concern about the environmental impact of the production and use of fossil fuels; •cybersecurity incidents, including data security breaches or computer viruses; and •certain factors discussed elsewhere in this filing. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our 2025 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise. Overview We are one of the largest owners and managers of oil and natural gas mineral interests in the United States ("U.S."). Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration. As of June 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. Recent Developments Development Activity At the end of the second quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating two 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 with the development agreements, with a total of 14 wells spud in the previous program year that ended on June 30, 2026. Of these wells, 6 gross (0.6 net) have turned to sales as of July 31, 2026, and 8 gross (0.7 net) are expected to turn to sales 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 was 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 18 laterals while keeping overall development levels unchanged. In May 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. The 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 2026, with Revenant spudding two additional 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 is currently drilling a pilot well in Cherokee County, consistent with the terms of the agreement. In the Permian Basin, Blue Arrow Operating is in progress on a development of 25 gross (1.9 net) wells in the southern Delaware Basin. Three 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. For additional information about our Shelby Trough development agreements, please read "Liquidity and Capital Resources - Shelby Trough Development Agreements." Acquisition Activity In the second quarter of 2026, consistent with our previously announced acquisition strategy, we acquired $37.2 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through June 2026, we have completed $299.7 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area. Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts. Oil prices increased during the first half of 2026 compared to the same period in 2025, primarily due to the conflict with Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices were lower during the first half of 2026 relative to the prior-year period. Natural gas prices were elevated early in 2026 due to winter weather and tighter inventories but generally moderated during the remainder of the first six months as production growth increased market supplies. Recent price strength at the end of the second quarter was driven by rising electric power demand and increased U.S. liquefied natural gas ("LNG") export volumes. Given the dynamic nature of commodity markets, we cannot reasonably estimate how long price levels or market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. The following table reflects commodity prices at the end of each quarter presented: 2026 2025 Benchmark Prices1 Second Quarter First Quarter Second Quarter First Quarter WTI spot oil ($/Bbl) $ 70.56 $ 102.86 $ 66.30 $ 71.87 Henry Hub spot natural gas ($/MMBtu) 3.34 2.88 3.26 4.11 1 Source: EIA 19 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: 2026 2025 U.S. Rotary Rig Count1 Second Quarter First Quarter Second Quarter First Quarter Oil 440 409 432 484 Natural gas 125 127 109 103 Other 8 7 6 5 Total 573 543 547 592 1 Source: Baker Hughes Incorporated Natural Gas Storage The majority of the production volumes attributable to our interests are 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 U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 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: 2026 2025 Region1 Second Quarter First Quarter Second Quarter First Quarter East 587 270 602 284 Midwest 706 350 688 364 Mountain 230 208 228 165 Pacific 313 258 287 202 South Central 1,086 775 1,148 758 Total 2,922 1,861 2,953 1,773 1 Source: EIA Natural Gas Exports Net natural gas exports averaged 17.2 Bcf per day during the second quarter of 2026, a 14% increase from the 2025 average. The EIA forecasts average exports of 17.3 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that 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. 20 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 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. •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 West Texas Intermediate ("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 American Petroleum Institute (“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. 21 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 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 June 30, 2026 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly 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. The Credit Facility allows but does not 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 June 30, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027. 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 three and six months ended June 30, 2025, 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. 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. 22 The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in thousands) Net income $ 106,358 $ 120,028 $ 119,630 $ 135,976 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 9,402 9,187 19,187 18,317 Interest expense 3,816 2,270 7,177 3,667 Income tax expense (benefit) (2) 8 60 (77) Accretion of asset retirement obligations 393 337 782 669 Seismic data acquisition costs 4,519 1,400 8,775 6,229 Equity–based compensation 2,480 1,960 6,031 5,015 Unrealized (gain) loss on commodity derivative instruments (35,618) (49,639) 16,688 2,751 Adjusted EBITDA 91,348 85,551 178,330 172,547 Adjustments to reconcile to Distributable Cash Flow: Change in deferred revenue — (1) (1) (2) Cash interest expense (3,554) (1,994) (6,653) (3,117) Preferred unit distributions (7,366) (7,367) (14,732) (14,733) Distributable Cash Flow $ 80,428 $ 76,189 $ 156,944 $ 154,695 23 Results of Operations Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 The following table shows our production, revenue, and operating expenses for the periods presented: Three Months Ended June 30, 2026 2025 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 863 863 — — % Natural gas (MMcf)1 13,133 13,710 (577) (4.2) % Equivalents (MBoe) 3,052 3,148 (96) (3.0) % Equivalents/day (MBoe) 33.5 34.6 (1.1) (3.2) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 87.08 $ 64.67 $ 22.41 34.7 % Natural gas ($/Mcf)1 3.07 3.37 (0.30) (8.9) % Equivalents ($/Boe) $ 37.82 $ 32.40 $ 5.42 16.7 % Revenue: Oil and condensate sales $ 75,151 $ 55,807 $ 19,344 34.7 % Natural gas and natural gas liquids sales1 40,275 46,189 (5,914) (12.8) % Lease bonus and other income 6,696 4,714 1,982 42.0 % Revenue from contracts with customers 122,122 106,710 15,412 14.4 % Gain (loss) on commodity derivative instruments, net 26,850 52,784 (25,934) (49.1) % Total revenue $ 148,972 $ 159,494 $ (10,522) (6.6) % Operating expenses: Lease operating expense $ 2,098 $ 2,990 $ (892) (29.8) % Production costs and ad valorem taxes 6,108 9,026 (2,918) (32.3) % Exploration expense 4,825 1,749 3,076 175.9 % Depreciation, depletion, and amortization 9,402 9,187 215 2.3 % General and administrative 16,076 13,924 2,152 15.5 % Other expense: Interest expense 3,816 2,270 1,546 68.1 % 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 quarter ended June 30, 2026 decreased compared to the quarter ended June 30, 2025. The decrease in total revenue in the second quarter of 2026 is primarily due to lower gains 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. Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025 due to increased realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended June 30, 2026 and 2025. 24 Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended June 30, 2026 as compared to the corresponding prior period. The decrease between the comparative periods is due to lower realized commodity prices and slightly decreased production volumes. The decrease in production was driven by lower 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 the quarters ended June 30, 2026 and 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 second quarter of 2026, gains from our commodity derivative instruments decreased compared to the same period in 2025. For the three months ended June 30, 2026, we recognized $8.8 million of realized losses and $35.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $3.2 million of realized gains and $49.6 million of unrealized gains in the same period in 2025. The unrealized gains on our commodity contracts during the second quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized gains 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 second quarter of 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play comprised the majority of lease bonus and other income for the second quarter of 2026, while the majority of lease bonus and other income in the second quarter of 2025 came from leasing activity in the Permian Basin and Bakken/Three Forks 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 June 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 June 30, 2026, production costs and ad valorem taxes decreased compared to the quarter ended June 30, 2025. The decrease was primarily due to $4.2 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production 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 June 30, 2026, exploration expenses increased compared to the same period in 2025, primarily due to higher expenditures for seismic costs incurred in connection with ongoing seismic 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 June 30, 2026 as compared to the same period in 2025 due to higher depletion 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 June 30, 2026, general and administrative expenses increased as compared to the 25 same period in 2025, primarily due to higher personnel costs, including $1.2 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025. Interest expense. Interest expense increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The following table shows our production, revenues, pricing, and expenses for the periods presented: Six Months Ended June 30, 2026 2025 Variance (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 1,648 1,579 69 4.4 % Natural gas (MMcf)1 28,399 28,563 (164) (0.6) % Equivalents (MBoe) 6,381 6,340 41 0.6 % Equivalents/day (MBoe) 35.3 35.0 0.3 0.9 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 78.44 $ 67.07 $ 11.37 17.0 % Natural gas ($/Mcf)1 3.65 3.66 (0.01) (0.3) % Equivalents ($/Boe) $ 36.51 $ 33.17 $ 3.34 10.1 % Revenue: Oil and condensate sales $ 129,265 $ 105,900 $ 23,365 22.1 % Natural gas and natural gas liquids sales1 103,683 104,424 (741) (0.7) % Lease bonus and other income 13,083 11,639 1,444 12.4 % Revenue from contracts with customers 246,031 221,963 24,068 10.8 % Gain (loss) on commodity derivative instruments, net (37,700) (3,217) (34,483) 1,071.9 % Total revenue $ 208,331 $ 218,746 $ (10,415) (4.8) % Operating expenses: Lease operating expense $ 3,991 $ 5,152 $ (1,161) (22.5) % Production costs and ad valorem taxes 15,308 19,211 (3,903) (20.3) % Exploration expense 9,450 6,859 2,591 37.8 % Depreciation, depletion, and amortization 19,187 18,317 870 4.7 % General and administrative 32,908 29,096 3,812 13.1 % Other expense: Interest expense 7,177 3,667 3,510 95.7 % 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 six months ended June 30, 2026 decreased slightly compared to the corresponding prior period. The decrease in total revenue is primarily due to increased losses on our commodity derivative instruments partially offset by increased oil and condensate sales as well as higher lease bonus and other income. 26 Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2026 increased compared to the corresponding prior period primarily due to higher production volumes and realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin and Bakken/Three Forks plays. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the six months ended June 30, 2026 and 2025. Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2026 were flat compared to the corresponding prior period. Both commodity prices and production volumes remained relatively consistent between the comparable periods. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the six months ended June 30, 2026 and 2025, respectively. Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2026, we recognized an increased loss from our commodity derivative instruments compared to the corresponding period in 2025. In the six months ended June 30, 2026, we recognized $21.0 million of realized losses and $16.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $0.5 million of realized losses and $2.7 million of unrealized losses in the same period in 2025. Unrealized losses on our commodity contracts during the six months ended June 30, 2026 were driven by changes in forward oil price curves, compared to the corresponding period in 2025 when unrealized losses were driven by changes in forward natural gas price curves. Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play and proceeds from the surface use waivers on our mineral acreage supporting solar development in Mississippi made up the majority of lease bonus and other income for the six months ended June 30, 2026, while a substantial portion of the activity in the corresponding period in 2025 came from leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana. Operating and Other Expenses Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to a reduction in nonrecurring service-related expenses, including workovers. Production costs and ad valorem taxes. For the six months ended June 30, 2026, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2025, primarily due to $6.5 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues. Exploration expense. For the six months ended June 30, 2026, exploration expense increased as compared to the six months ended June 30, 2025. The increase was 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. Depreciation, depletion, and amortization increased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area. General and administrative. For the six months ended June 30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $2.3 million of cash compensation and $0.9 million of equity-based compensation, driven by increased 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 six months ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility. 27 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 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-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. 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 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 June 30, 2026, we had not made any repurchases under the program. 28 Cash Flows The following table shows our cash flows for the periods presented: Six Months Ended June 30, 2026 2025 Change (in thousands) Cash flows provided by operating activities $ 155,527 $ 145,311 $ 10,216 Cash flows used in investing activities (52,778) (42,687) (10,091) Cash flows used in financing activities (102,553) (102,624) 71 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 increased for the six months ended June 30, 2026 as compared to the same period of 2025. The increase was primarily driven by higher oil sales due to increased realized oil prices and production volumes in the six months ended June 30, 2026. The overall increase was partially offset by higher cash paid for the settlement of commodity derivatives. Investing Activities. Net cash used in investing activities in the six months ended June 30, 2026 increased as compared to the same period of 2025. The increase was primarily due to higher expenditures for acquisitions of oil and natural gas properties and leasehold costs in the six months ended June 30, 2026 compared to the same period of 2025. Financing Activities. Net cash used in financing activities remained consistent for the six months ended June 30, 2026 as compared to the same period of 2025. The decreased distributions paid to common unitholders for the six months ended June 30, 2026, compared to the same period of 2025 was partially offset by higher repayments of our Credit Facility. Development Capital Expenditures Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.3 million during the six months ended June 30, 2026. We also spent $6.3 million to acquire leases in areas around our drilling programs during the six months ended June 30, 2026. Acquisitions During the six months ended June 30, 2026, we acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $48.7 million, including capitalized direct transaction costs. The consideration paid consisted of $45.9 million in cash that was funded with borrowings under our Credit Facility and funds from operating 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. See "Note 3 – Oil and Natural Gas Properties" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. 29 Shelby Trough Development Agreements We are party to a series of Joint Exploration Agreements ("JEAs"; each, a "JEA") with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage and reduced royalty rates in exchange for meeting minimum annual drilling commitments, as defined by either a minimum number of wells or minimum aggregate lateral feet drilled. Each JEA also includes a banking provision that allows operators that exceed their annual drilling commitments to carry forward excess drilling activity, measured by wells drilled or aggregate lateral feet, to satisfy future obligations, subject to defined caps. The agreements also allow operators to temporarily suspend drilling obligations if natural gas prices fall below certain thresholds. The duration of any such suspension period is subject to limitations specified in the agreements. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs. For additional information about our development activities in the Shelby Trough, please read "Recent Developments." Adamas Joint Exploration Agreements We have two JEAs originally entered into with Aethon Energy and now operated by Adamas, covering a portion of our acreage in San Augustine County and Angelina County in East Texas. The agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas. Adamas drilled a total of 14 wells during the program year that ended on June 30, 2026 and applied 2 of its 10 banked wells toward its commitment. As of July 31, 2026, 8 of those wells had not yet turned to sales and are expected to begin production during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026. Revenant Joint Exploration Agreement 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. In November 2025, we entered into an amendment to the JEA that maintained the original 6-well commitment for Program Year 1, while revising the structure for subsequent years. After Program Year 1, well count commitments convert to completed gross lateral-foot commitments at a ratio of one well per 7,000 lateral feet, allowing Revenant to drill longer laterals while maintaining overall commitment levels. In May 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. The amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program. 30 The table below summarizes the minimum gross lateral-foot drilling commitments under the amended agreement, following Program Year 1: Revenant Drilling Commitments1 Program Year Calendar Year AOI 1 AOI 2 AOI 3 Total Gross Lateral Feet 2 2027 56,000 7,000 — 63,000 3 2028 70,000 — — 70,000 4 2029 84,000 14,000 14,0002 112,000 5 and thereafter 2030 and beyond 105,000 35,000 21,000 161,000 1 Lateral-feet drilled in any AOI may be used to satisfy drilling commitments in other AOIs, except for the AOI 2 commitment in Program Year 2. 2 Revenant has the option to elect into the AOI 3 drilling commitment by June 30, 2028. If they do not make this election, the AOI 3 acreage and associated drilling commitment will be removed from the development program. Caturus Joint Exploration Agreement In November 2025, we entered into a JEA with Caturus covering an expanded portion of our Shelby Trough acreage, primarily in Angelina, Cherokee, Houston, and Nacogdoches counties in Texas. The agreement grants Caturus exclusive development rights across the contract area and requires minimum annual drilling commitments to maintain such rights. These commitments are measured in completed lateral feet on a net basis attributable to our mineral ownership interest and include pilot and test wells in the initial program years. The minimum net lateral-foot commitments escalate over a six-year period. The table below summarizes the minimum net lateral-foot drilling commitments under the agreement: Caturus Drilling Commitments Program Year Calendar Year Net Lateral Feet 1 2026 6,000 2 2027 12,000 3 2028 12,600 4 2029 16,800 5 2030 21,000 6 and thereafter 2031 and beyond 25,200 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 2025, October 2025 and April 2026 at $580.0 million. After each redetermination, we elected to maintain cash commitments under the Credit Facility at $375.0 million. The next semi-annual redetermination is scheduled for October 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 June 30, 2026, we were in compliance with all debt covenants. See "Note 6 – Credit Facility" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. Material Cash Requirements As of June 30, 2026, there have been no material changes to our material cash requirements previously disclosed in our 2025 Annual Report on Form 10-K. 31 Critical Accounting Policies and Related Estimates As of June 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.