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

•the amount of oil, natural gas and NGLs we produce;

•the prices at which we sell our oil, natural gas and NGL production;

•the amount and timing of settlements on our commodity derivative contracts;

•the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

•the level of our operating costs, including payments to our general partner and its affiliates for general and administrative expenses; and the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate.

•worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs;

•the level of global oil and natural gas exploration and production;

•political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditionsheightened geopolitical tensions in regions like South America,America (including Venezuela), Central America, China and Russia, and acts of terrorism or sabotage;

•the ability of and actions taken by members of Organization of the Petroleum Exporting Countries (“OPEC”) and other oil-producing nations in connection with their arrangements to maintain oil prices and production controls;

•the impact on worldwide economic activity of an epidemic, outbreak or other public health events, such as COVID-19events;

•the proximity, capacity, cost and availability of gathering and transportation facilities;

•localized and global supply and demand fundamentals;

•weather conditions across the globe;

•technological advances affecting energy consumption and energy supply;

•speculative trading in commodity markets, including expectations about future commodity prices;

•the proximity of our natural gas, NGL and oil production to, and capacity, availability and cost of, natural gas pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices;

•the impact of energy conservation efforts;

•the price and availability of alternative fuels;

•stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas to minimize the emission of greenhouse gases;

•the impact of tariffs on energy products and other imports to and exports from foreign nations, including Mexico, Canada and China;

•domestic, local and foreign governmental regulation and taxes; and overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Changes in oil, natural gas and NGL prices have a significant impact on the amount of oil, natural gas and NGL that we can produce economically, the value of our reserves and on our cash flows. Historically, oil, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. For example, during the period from January 1, 20222023 through December 31, 2024,2025, prices for crude oil and natural gas reached a high of $123.70$93.68 per Bbl and $9.68$5.29 per MMBtu, respectively, and a low of $65.75$55.27 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased drastically in the first half of 2022 due to demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 andduring the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in December 2023 but continuing hostilities and higher global consumption pushed prices higher in the first half of 2024. However, increased supply led to lower prices in the second half of 2024.2024 and continued throughout 2025 as OPEC unwound previous output cuts leading to rising inventories. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

We may be unable to pay quarterly distributions to our unitholders without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future reserves and production and, therefore, our cash flow and ability to make distributions are highly dependent on our success in efficiently developing, optimizing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions.acquisitions or dispositions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

Prior to 2022,2023, our historical impairment of proved properties included $311.5 million of proved property impairments from 2014 through 2021.2022. DueAs a result of the Cross Timbers Transactions, we evaluated the recoverability of the Cross Timbers oil and gas assets and recorded an impairment of long-lived assets of $42.4 million for the year ended December 31, 2025. The impairment was related to theour improvementassets in commoditythe pricingPermian environmentBasin andthat industryare conditions,within weour didCross notTimbers recordjoint anyventure. impairments in 2022 or 2024. However,Additionally, with the decline of commodity prices late in 2023, increased costs and a change in our approach to recording proved undeveloped reserves, we recorded an impairment of long-lived assets of $223.4 million for the year ended December 31, 2023. The impairment was related to our assets in the Texas Permian Basin that are within our Cross Timbers joint venture. Due to the improvement in commodity pricing environment and industry conditions, we did not record any impairments in 2024. In the future, if commodity prices fall below certain levels, our production, proved reserves and cash flows will be adversely impacted and we may be required to record additional impairments, which could be material. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which may be determined at the discretion of our lenders. See “—Any significant reduction in the borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

•unexpected or adverse drilling conditions;

•delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements including permitting requirements, limitations on or resulting from wastewater discharge and the disposal of exploration and production wastes, including subsurface injections;

•elevated pressure or irregularities in geological formations;

•shortages of or delays in obtaining equipment and qualified personnel;

•facility or equipment failures or accidents;

•lack of available gathering facilities or delays in construction of gathering facilities;

•lack of available capacity on interconnecting transmission pipelines;

•adverse weather conditions, such as hurricanes, lightning storms, flooding, tornadoes, snow or ice storms and changes in weather patterns;

•issues related to compliance with, or changes in, environmental and other governmental regulations;

•environmental hazards, such as oil and natural gas leaks, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•declines in oil, natural gas and NGL prices;

•the availability and timely issuance of required governmental permits and licenses; and title defects or legal disputes regarding leasehold rights.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our perceived credit rating.worthiness. For example, during 2022 and the first half of 2023, the Federal Reserve raised the target range for the federal funds rate by 525 basis points to a range of 5.25% to 5.50% as of August 2023. While the Federal Reserve lowered the federal funds rate during 20242025 to a range of 4.25%3.5% to 4.50%,3.75%, our interest rate on our Credit Facility remains elevated at 8.3%7.6% as of December 31, 2024.2025. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

We incurred significant indebtedness to finance the Williston Basin Acquisitions.Transactions.

As of December 31, 2024,2025, we have $150.0$284.0 million of outstanding borrowings under our Credit Facility. This resulted in an increase to our net debt-to-Adjusted EBITDAX ratio to approximatelybetween one and two times. We also committed to a $70.0 million deferred payment on the WRE Acquisition that is due July 31, 2026.

In accordance with the JV LLCA, Cross Timbers is managed by us and governed by a member management committee ("MMC") comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities. The JV LLCA requires that certain matters, including certain material contracts or acquisitions, mergers, sale of substantially all assets or other change of control transactions, and transfers of our interest to a third party, be approved by unanimous consent of the voting members of the management committeeMMC and therefore such actions require the approval of the XTO Entities. In February 2026, the voting members of the MMC unanimously approved the execution of the pending Cross Timbers Transactions, which, if consummated, would constitute a sale of certain of the assets of Cross Timbers. There can be no assurance that the conditions to closing for any or all of the pending Cross Timbers Transactions will be satisfied. Our ability to make distributions to our unitholders depends in part on the performance of this entity and its ability to distribute funds to us. We face certain risks associated with shared control, and the XTO Entities may at any time have economic, business or legal interests or goals that are inconsistent with ours.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive sincefor 2022,the last several years, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate in 2024,moderate, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. Though we incorporated inflationary factors into our 20252026 business plan, inflation may outpace those assumptions. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. If we are unable to recover higher costs through higher commodity prices, our current revenue stream could be adversely impacted and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

In addition, continued hostilities related to the Russian invasion of Ukraine, hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, such as another surge in COVID-19 cases or decreased demand from China, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations.

Changes in U.S. trade policy, including the imposition of increased or additional tariffs and the resulting consequences, could have a material adverse effect on our results of operations, financial position and cash flows.

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.

•disruption in the demand for oil, natural gas and other petroleum products;

•intentional project delays until commodity prices stabilize;

•potentially higher borrowing costs in the future;

•a need to preserve liquidity, which could result in reductions, delays or changes in our capital expenditures;

•liabilities resulting from operational delays due to decreased productivity resulting from stay-at-home orders affecting our workforce or facility closures;

•future asset impairments, including impairment of our natural gas properties, oil properties, and other property and equipment; and infections and quarantining of our employees and the personnel of vendors, suppliers and other third parties.

Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil, NGL and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities. While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. For example, revenues decreasedincreased $97.9$118.2 million, or 26%,42%, from $380.7 million for the year ended December 31, 2023 to $282.8 million for the year ended December 31, 2024.2024 to $401.0 million for the year ended December 31, 2025. The decreaseincrease was primarily attributable to a decrease in the average selling price, excluding the effects of derivatives, on oil of 4%, resulted in a decrease in revenue of $7.2 million and on gas of 60%, resulted in a decrease in revenue of $89.5 million. Additionally, net losses on our hedging activity of $25.7 million, of which $113.6 million were related to increased unrealized losses partially offset by $87.9 million related to lower realized losses. These decreases were partially offset by an increase in production of 1621,758 MBoe which resulted in increased revenue of $22.4$96.1 million primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and an increase in average selling price, excluding the effects of derivatives, on gas of 27%, resulting in an increase in revenue of $15.9 million. Additionally, net gains on our hedging activity of $40.4 million, of which $31.5 million were related to unrealized gains and $8.9 million related to higher realized gains. These increases were partially offset by a decrease in the average selling price, excluding the effects of derivatives, on NGLsoil of 8%,16%, resulting in ana increasedecrease in revenue of $2.2$30.8 million and on NGLs of 12%, resulting in a decrease in revenue of $3.5 million.

Furthermore, SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional PUD reserves as we pursue our drilling program. To the extent that natural gas and oil prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our PUD reserves if we do not drill those wells within the required five-year time frame. If we choose not to develop PUD reserves, or if we are not otherwise able to successfully develop them, then we will be required to remove the associated volumes from our reported proved reserves. During the years ended December 31, 2023, 2024 and 2025, no proved undeveloped reserves were converted to proved developed reserves. The costs we incurred relating to the development of oil and natural gas reserves in 2023, 2024 and 2025 did not result in the conversion of any proved undeveloped reserves to proved developed reserves because they were primarily related to drilling wells in the San Juan Basin and Permian Basin that did not have proved undeveloped reserves assigned at the beginning of the year, and which resulted in additional proved developed reserves The preparation of reserve estimates requires the projection of production rates and the timing of development expenditures based on an analysis of available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

For the year ended December 31, 2024,2025, Chevron USA, Gunvor USA and GunvorPlains USAAll American together accounted for almostmore 46%than 42% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2023,2024, Chevron USA and CIMAGunvor EnergyUSA together accounted for more than 42%46% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties—Operations—Marketing and Customers.”

•incur certain liens or permit them to exist;

•merge or consolidate with another company;

On JuneMay 28,15, 2024,2025, we completed the 2025 Offering for the sale of 6.5 million11,666,667 common units at a price of $20.00$15.00 per common unit,unit which resultedresulting in net proceeds of $122.5approximately $165.6 million net of underwriting discounts, commissions and other costs.costs (the "2025 Offering"). On JulyMay 2,19, 2024,2025, we completed the sale of an additional 975,0001,750,000 common units at a price of $20.00$15.00 per common unit pursuant to the underwriter’sunderwriter's exercise in full of its option to purchase additional common units in the 2025 Offering, resulting in additional proceeds of $18.7approximately $23.9 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the 2025 Offering to fund a portion of the cash consideration for the WillistonWRE Acquisitions.Acquisition.

The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 20222023 through December 31, 2024,2025, prices for crude oil and natural gas reached a high of $123.70$93.68 per Bbl and $9.68$5.29 per MMBtu, respectively, and a low of $65.75$55.27 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased drastically in the first half of 2022 due to demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 andduring the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in December 2023 but continuing hostilities and higher global consumption pushed prices higher in the first half of 2024. However, increased supply led to lower prices in the second half of 2024 decliningand continued throughout 2025, as OPEC unwound previous output cuts which lead to $72.73rising oil inventories. Oil prices were to $65.21 per Bbl as of January 30, 2025. Natural gas prices reached a high of $9.68 per MMbtu in August 2022 before declining to $1.58 per MMBtu in February 2024 and then rebounding to $3.05 per MMbtu as of January 30, 2025.2026. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive sincefor 2022,the last several years, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate in 2024,moderate, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. Though we incorporated inflationary factors into our 2026 business plan, inflation may outpace those assumptions. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. For example, mostthe majority of our gas is sold at the San Juan basis. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. The following is a comparison of average pricing excluding and including the effects of derivatives:

The price we receive for our oil and natural gas production is generally less than the NYMEX prices because of adjustments for basis, relative quality and other factors. WeAt havetimes, enteredwe enter into basis swap agreements for a portion of our gas production that effectively fix the basis adjustment for our delivery locations.

In the year ended December 31, 2025, all of our hedging activities increased oil revenue $26.2 million, NGL revenue $0.0 million and gas revenue $11.7 million. In the year ended December 31, 2024, all of our hedging activities increased oil revenue $0.2 million and decreased NGL revenue $0.0 million and gas revenue $2.8 million. In the year ended December 31, 2023, all of our hedging activities increased oil revenue $2.3 million, NGL revenue $1.4 million and gas revenue $19.4 million. In the year ended December 31, 2022, all of our hedging activities decreased oil revenue $45.8 million, NGL revenue $5.6 million and gas revenue $151.8 million.

(a)Reductions to NYMEX gas price for delivery location

General and administrative expenses consist primarily of personnel related costs and are partially offset by certain reimbursements of overhead expenses. However, we do not expect to experience a material change in our cash cost structure, other than as set forth below under “Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

Texas does not currently impose a personal income tax on individuals,individuals. butHowever, itTexas does impose anthe entityRevised levelTexas taxFranchise Tax (commonly referred to whichas wethe are"Texas subjectMargin Tax") on corporationscorporations, limited partnerships, and other entities.entities Whileconducting webusiness doin Texas. Although the Texas Margin Tax is not payconsidered a traditional income tax, it has the characteristics of an income tax insince Texas,it weis determined by applying a tax rate to a base that considers Texas-sourced revenues and expenses. We are subject to the Texas franchiseMargin taxes.Tax.

•production volumes;

•realized prices on the sale of oil, NGLs and natural gas;

•production expenses;

•acquisition and development expenditures

•Adjusted EBITDAX; and

•Cash Available for Distribution.

We use cash available for distribution to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX plus cash interest income less cash interest expense, exploration expense and development costs. Development costs include all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances.

(1)Oil and condensate prices include both realized and unrealized gains and losses from derivatives. The unrealized gains were $5.8$19.1 million for the year ended December 31, 2025 ,$5.8 million for the year ended December 31, 2024 and $9.5 million for the year ended December 31, 20232023. andThe unrealizedrealized lossesgains were $13.0$7.1 million for the year ended December 31, 2022.2025 Theand realized losses were $5.6 million for the year ended December 31, 2024,2024 and $7.1 million for the year ended December 31, 2023 and $32.8 million for the year ended December 31, 2022.2023.

(2)Natural gas liquids prices include both realized and unrealized gains and losses from derivatives. The unrealized gains were $0.0 million for the year ended December 31, 2025, unrealized losses were $0.5 million for the year ended December 31, 2024,2024 and unrealized gains were $1.0 million for the year ended December 31, 20232023. andThe unrealizedrealized lossesgains were $1.0$0.0 million for the year ended December 31, 2022.2025 The realized gains were $0.5,$0.5 million for the year ended December 31, 2024 and $0.4 million for the year ended December 31, 2023 and realized losses were $4.6 million for the year ended December 31, 2022.2023.

(3)Natural gas prices include both realized and unrealized gains and losses from derivatives. The unrealized gains were $5.0 million for the year ended December 31, 2025, unrealized losses were $12.8 million for the year ended December 31, 2024,2024 and unrealized gains were $95.8 million for the year ended December 31, 20232023. andThe unrealizedrealized lossesgains were $99.2$6.6 million for the year ended December 31, 2022.2025 The realized gains wereand $10.0 million for the year ended December 31, 2024 and realized losses were $76.4 million for the year ended December 31, 2023 and $52.6 million for the year ended December 31, 2022.2023.

Production expenses increased $5.6$35.9 million, or 4%,24%, from $144.7 million for the year ended December 31, 2023 to $150.3 million for the year ended December 31, 2024.2024 to $186.2 million for the year ended December 31, 2025. Of this increase, $10.0$31.2 million is attributable to production from the Williston Basin acquisitions. ThisAdditionally, the increase was partiallydue offsetto by decreasedincreased maintenance and energypersonnel costs on our historical properties.

On a per unit basis, production expenses increased from $17.24 per Boe sold for the year ended December 31, 2023 to $17.56 per Boe sold for the year ended December 31, 2024.2024 to $18.05 per Boe sold for the year ended December 31, 2025. The increase is primarily related to the increased costs per Boe from our historical properties as decreasedactual costs increased while production morefrom thanour offsethistorical decreasedproperties decreased. Additionally, costs inwere these properties. This increase was partially offset by lower costshigher per Boe fromon theour Williston Basin acquisitions.properties in 2025.

InterestTaxes, expensetransportation, and other increased $3.5$8.3 million, or 78%,14%, from $4.4$60.4 million for the year ended December 31, 20232024 to $7.9$68.8 million for the year ended December 31, 2024.2025. The increase is primarily attributable to increased borrowingsoil, dueNGLs toand natural gas volumes and natural gas prices partially offset by the Willistondecrease Basinin acquisitionsoil and aNGL higher interest rate.prices.

Our primary sources of liquidity and capital are cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $284.0 million at December 31, 2025 and $150.0 million at December 31, 2024 and $21.0 million at December 31, 2023,2024, and the remaining availability under our Credit Facility was $126.0 million at December 31, 2025 and $125.0 million at December 31, 2024 and $144.0 million at December 31, 2023.2024. Additionally, we had negative net working capital (including cash and excluding the effects of derivative instruments) of $71.8 million at December 31, 2025 and $2.5 million at December 31, 20242024. andThe positivenegative net working capital of $14.1$71.8 million at December 31, 2023.2025 is primarily related to the $70.0 million deferred payment on the WRE Acquisition that is due July 31, 2026.

On JuneMay 28,15, 2024,2025, we completed the 2025 Offering for the sale of 6.5approximately million11,666,667 common units at a price of $20.00$15.00 per common unit which resultedresulting in net proceeds of $122.5approximately $165.6 million net of underwriting discounts, commissions and other costs. On JulyMay 2,19, 2024,2025, we completed the sale of an additional 975,0001,750,000 common units at a price of $20.00$15.00 per common unit pursuant to the underwriter’sunderwriter's exercise in full of its option to purchase additional common units in the 2025 Offering, resulting in additional net proceeds of $18.7approximately million$23.9 netmillion, ofafter deducting underwriting discounts, commissions and other costs. We used a portion of the net proceeds from the 2025 Offering to fund a portion of the cash consideration for the WillistonWRE Acquisitions.Acquisition.

Our net credit facility debt as of December 31, 20242025 was $142.7$274.6 million (less cash of $7.3$9.4 million). These borrowings under our Credit Facility, which increased our net debt-to-EBITDAX ratio to approximatelybetween one times,and two, were incurred to fund the remainder of the Williston Basin Acquisitions.Transactions. We expect to carrymaintain this levelrange of debtleverage moving forward.

As a publicly traded partnership, our primary sources of liquidity and capital resources are from cash flow generated by operating activities and borrowings under our Credit Facility. Historically, our primary sources of liquidity have also included capital contributions by our pre-IPO equity holders, but we do not expect to rely on pre-IPO equity holders for capital going forward. We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. Our fourth quarter distribution of $0.61$0.30 per unit with respect to cash available for distribution for the three months ended December 31, 2024,2025, was declared on MarchFebruary 04,26, 20252026 and will be paid on March 21,17, 20252026 to unitholders of record on March 14,10, 2025.2026.

We incurred costs of approximately $28.0$71.1 million for drilling, completion and recompletion activities and facilities costs in 20242025 and we have budgeted approximately $30 - $50$70 million for such costs in 2025.2026. We expect to fund these capital expenditures from cash flow from operations.

Net cash provided by operating activities increased $32.1$8.9 million for the year ended December 31, 20242025 compared to the year ended December 31, 20232024 primarily as a result of increased production and lowerhigher expensesnatural gas prices partially offset by higher expenses and lower oil and natural gas prices in 20242025 compared to 2023.2024.

Net cash used by investing activities increased $242.1$47.0 million for the year ended December 31, 20242025 compared to the year ended December 31, 20232024 due to an increase in development costs of $48.5 million partially offset by a decrease in proved property and other property acquisitions of $254.6 million related to the Williston Basin Acquisitions partially offset by a decrease in development costs of $12.6$1.5 million.

Net cash provided by financing activities increased $217.4$37.4 million for the year ended December 31, 20242025 compared to the year ended December 31, 20232024 due to increased proceeds from public offerings of $48.3 million and an increase in net borrowings under our credit facility of $221.0 million and increased proceeds from public offerings of $35.0$5.0 million partially offset by increased distributions to unitholders of $35.6 million and increased debt offering costs of $3.0$16.1 million.

Unless otherwise stated or the context indicates otherwise, references in this Quarterly Report to “our general partner” refers to TXO Partners GP, LLC, a Delaware limited liability company, and the terms “partnership,” the “Company,” “we,” “our,” “us” or similar terms refer to TXO Partners, L.P., a Delaware limited partnership (the "Partnership" or “TXO Partners”) and its subsidiaries. Unless otherwise indicated, throughout this discussion the term “MBoe” refers to thousands of barrels of oil equivalent quantities produced for the indicated period, with natural gas and NGL quantities converted to Bbl on an energy equivalent ratio of six Mcf to one barrel of oil.

We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional and unconventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas, the San Juan Basin of New Mexico and Colorado and the Williston Basin of Montana and North Dakota.

On April 30,1, 2026, the secondfirst Cross Timbers Transaction closed resulting in net proceeds of approximately $30.8$8.2 million, subject to customary purchase price adjustments, of which all was allocated to proved properties.adjustments.

The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2025 through MarchJune 31,30, 2026, NYMEX prices for crude oil and natural gas reached a high of $102.88$112.95 per Bbl and $7.46 per MMBtu, respectively, and a low of $55.27 per Bbl and $2.70$2.52 per MMBtu, respectively. Oil prices increased in the first quarterhalf of 2026 due to hostilities in the Middle East which led to unexpected production cuts and supply constraints. These increases began to moderate in April 2026 due to the cease fire announcement, however, oil prices are increasing again with the resumption of hostilities, and oil prices remain volatile.

With our anticipated cash flows from our long-lived property base, we intend to provide dynamic allocation ofallocate funds to prudently meet our goals. These goals include the highest projected economic returns on our capital budget, acquisition opportunities that fulfill our strategy, and cash distributions for the life of our legacy assets.distributions. From time to time, we may choose to prioritize the repayment of debt incurred in acquisitions to support the longer-term financial stewardship of our business. At other times, given fluctuations in industry costs and commodity prices, we may modify our capital budget or cash balancesdistribution to shift funds towards cash distributions.policy. We will use all of these tools to support our underlying strategy as a “production and distribution” enterprise.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, war, geopolitical issues, inflation, tariffs, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Rising inflation has been pervasive for the last several years, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steelsteel, diesel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

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

Oil and condensate prices include both realized gains and losses and unrealized gains and losses from derivatives. Unrealized lossesgains were $84.2$41.9 million for the three months ended MarchJune 31,30, 2026 and unrealized gains were $3.1$3.3 million for the three months ended MarchJune 31,30, 2025. Realized losses were $8.4$28.5 million for the three months ended MarchJune 31,30, 2026 and realized gains were $0.1$2.0 million for the three months ended MarchJune 31,30, 2025.

Natural gas liquids prices include both realized gains and unrealized gains and losses from derivatives. Unrealized gains were $23.0$16.0 thousand for the three months ended MarchJune 31,30, 2026 and unrealized losses were $13.0$12.0 thousand for the three months ended MarchJune 31,30, 2025. There were no realized gains or losses for either the three months ended MarchJune 31,30, 2026 orand no realized gains for the three months ended MarchJune 31,30, 2025.

Natural gas prices include both realized gains and unrealized gains and losses from derivatives. Unrealized gainslosses were $8.5$2.3 million for the three months ended MarchJune 31,30, 2026 and unrealized lossesgains were $10.6$4.1 million for the three months ended MarchJune 31,30, 2025. Realized lossesgains were $7.3$5.3 million for the three months ended MarchJune 31,30, 2026 and $2.0$5.4 million for the three months ended MarchJune 31,30, 2025.

Production expenses increaseddecreased $5.5$1.9 million, or 13%,4%, from $42.3$43.3 million for the three months ended MarchJune 31,30, 2025 to $47.7$41.5 million for the three months ended MarchJune 31,30, 2026. ThisOf increasethis decrease, $7.2 million is primarily due to increased costs of $3.3 million relatedattributable to the Willistonsale Acquisitionof Cross Timbers Energy assets and increaseddecreased maintenance and electricity costs on our historical properties.properties partially offset by an increase of $6.1 million attributable to production from the Williston Basin acquisitions.

On a per unit basis, production expenses decreased from $18.15$18.30 per Boe sold for the three months ended MarchJune 31,30, 2025 to $16.43$15.97 per Boe sold for the three months ended MarchJune 31,30, 2026. The decrease is primarily related to decreased costs principally attributable to the Cross Timbers Energy sale and an increase in production of 577228 MBoe partially offset by increased costs attributable to production from the Williston Acquisition.MBoe.

Taxes, transportation, and other increased $1.9$4.5 million, or 11%,29%, from $17.9$15.2 million for the three months ended MarchJune 31,30, 2025 to $19.8$19.7 million for the three months ended MarchJune 31,30, 2026. The increase is primarily attributable to the increase in production and higher oil and NGL prices partially offset by decreased oil,natural gas and NGL prices excluding the effects of derivatives.prices.

On a per unit basis, taxes, transportation, and other decreasedincreased from $7.68$6.43 per Boe sold for the three months ended MarchJune 31,30, 2025 to $6.80$7.59 per Boe sold for the three months ended MarchJune 31,30, 2026. The decreaseincrease is primarily related to increased productioncosts partially offset by increased costs.production.

Depreciation, depletion, and amortization (“DD&A”) increased $7.4$2.3 million, or 35%,11%, from $21.4$21.7 million for the three months ended MarchJune 31,30, 2025 to $28.8$24.0 million for the three months ended MarchJune 31,30, 2026. The increase is primarily attributable to the DD&A from increased production associated with the Williston AcquisitionBasin acquisitions which has a higher rate than the historical properties partially offset by decreased production on our historical properties.properties and the sale of Cross Timbers Energy.

On a per unit basis, depreciation, depletion, and amortization increased from $9.20$9.16 per Boe sold for the three months ended MarchJune 31,30, 2025 to $9.92$9.23 per Boe sold for the three months ended MarchJune 31,30, 2026. The increase is primarily related to the production associated with the Williston Acquisition,Basin acquisitions, which has a higher rate than the historical properties.

General and administrative (“G&A”) expenses increaseddecreased $2.4$4.7 million, or 97%,50%, from $2.4$9.5 million for the three months ended MarchJune 31,30, 2025 to $4.8 million for the three months ended MarchJune 31,30, 2026. The increasedecrease is primarily attributable to higherlower personnel costs of $1.7$4.0 million, principally due to decreased amortization of unit-based compensation.

On a per unit basis, G&A expense increaseddecreased from $1.05$3.99 per Boe sold for the three months ended MarchJune 31,30, 2025 to $1.66$1.83 per Boe sold for the three months ended MarchJune 31,30, 2026. The increasedecrease is primarily related to increaseddecreased costs partially offset byand increased production.

Other income decreasedincreased $0.7$2.6 million, or 7%,45%, from $9.5$5.9 million for the three months ended MarchJune 31,30, 2025 to $8.9$8.5 million for the three months ended MarchJune 31,30, 2026. The decreaseincrease is primarily attributable to the gain on the Cross Timbers Energy asset sale of $1.6 million and bonus payments from term leases of $1.4 million partially offset by lower CO2 and plant income of $1.7 million and the absence of bonus payments from term leases of $1.2 million partially offset by increased marketing income of $1.5$0.5 million. The CO2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO2 assets in Colorado.

Interest expense increased $2.1$3.0 million, or 59%,117%, from $3.6$2.6 million for the three months ended MarchJune 31,30, 2025 to $5.7$5.6 million for the three months ended MarchJune 31,30, 2026. The increase is primarily attributable to increased borrowings and amortization of capitalized debt costs partially offset by a lower average interest rate.

Our primary sources of liquidity and capital will be cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $270.0$263.0 million at MarchJune 31,30, 2026 and $284.0 million at December 31, 2025, and the remaining availability under our Credit Facility was $140.0$147.0 million at MarchJune 31,30, 2026 and $126.0 million at December 31, 2025. Additionally, we had negativepositive net working capital (including cash and excluding the effects of derivative instruments) of $70.0$22.1 million at MarchJune 31,30, 2026 and negative net working capital of $71.8 million at December 31, 2025. The positive working capital of $22.1 million at June 30, 2026 is primarily related to the cash held at Cross Timbers Energy partially offset by the $70.0 million deferred payment on the Williston Acquisition that was due July 31, 2026. The negative working capital of $70.0 million at March 31, 2026 and $71.8 million at December 31, 2025 is primarily related to the $70.0 million deferred payment on the Williston Acquisition that is due July 31, 2026.Acquisition.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. Our firstsecond quarter distribution of $0.36$0.40 per unit with respect to cash available for distribution for the three months ended MarchJune 31,30, 2026, was declared on MayAugust 4, 2026 and will be paid on MayAugust 22,21, 2026 to unitholders of record on MayAugust 15,14, 2026.

Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures.expenditures offset by sales of properties. Our capital expenditures including acquisitions and netdispositions resulted in cash provided by investing activities of sales were $4.4$73.1 million for the threesix months ended MarchJune 31,30, 2026 and $6.8used by investing activities of $49.6 million for the threesix months ended MarchJune 31,30, 20252025. Included in investing activities in the threesix months ended MarchJune 31,30, 2026,2026 isare $6.2$100.3 million relatedof toproceeds TXOfrom Partners'the sharesale of deposits related to the Cross Timbers Transactions.properties.

We incurred costs of approximately $8.7$33.1 million for drilling, completion and recompletion activities and facilities costs in the threesix months ended MarchJune 31,30, 2026 and we haveexpect budgetedto spend approximately $70.0$80 million for such costs in 2026.

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

Net cash provided by operating activities increased $2.8$25.0 million for the threesix months ended MarchJune 31,30, 2026 compared to the threesix months ended MarchJune 31,30, 2025 due to increased production and improved operating results, excluding the effects of derivatives partially offset by higherincreased expensescosts and lower oil,NGL and gas and NGL prices.

Net cash provided by (used by) investing activities

Net cash usedprovided by investing activities decreasedincreased $2.5$122.7 million for the threesix months ended MarchJune 31,30, 2026 compared to the threesix months ended MarchJune 31,30, 2025 primarily due to proceeds from the sale of propertythe Cross Timbers Energy assets of $100.3 million and equipmenta of $6.3 million partially offset by an increasedecrease in proved property acquisitions of $2.5$33.1 million andpartially offset by increased development costs of $1.1$9.7 million.