TXO Partners, L.P.
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
TXO$13.13+3.5%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-04.
0001559432-25-000035
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
0001193125-26-076813
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 153 previous paragraphs and 151 current paragraphs.
96 unchanged; 46 reworded; 8 added; 10 removed; 1 previous and 1 current paragraphs rearranged.
Tables are not compared: 12 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (8)
Current report
Asset Disposition
Current report
In February 2026, Cross Timbers executed agreements to dispose of certain oil and gas assets owned by Cross Timbers pursuant to purchase and sale agreements with multiple private buyers. We anticipate realizing about $40 million of aggregate proceeds from the Cross Timbers Transactions, subject in each case to customary purchase price adjustments, which we intend to use to pay a portion of the deferred payment for the WRE Acquisition. As 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 Cross Timbers Transactions are expected to close in the second quarter of 2026, subject to customary closing conditions. There can be no assurance that all of the conditions to closing any or all of the Cross Timbers Transactions will be satisfied.
Current report
(a)
Current report
Texas does not currently impose a personal income tax on individuals. However, Texas does impose the Revised Texas Franchise Tax (commonly referred to as the "Texas Margin Tax") on corporations, limited partnerships, and other entities conducting business in Texas. Although the Texas Margin Tax is not considered a traditional income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers Texas-sourced revenues and expenses. We are subject to the Texas Margin Tax.
Current report
Taxes, transportation, and other increased $8.3 million, or 14%, from $60.4 million for the year ended December 31, 2024 to $68.8 million for the year ended December 31, 2025. The increase is primarily attributable to increased oil, NGLs and natural gas volumes and natural gas prices partially offset by the decrease in oil and NGL prices.
Current report
Deferred Payment
Current report
At December 31, 2025, we had a $70.0 million deferred payment that we incurred as part of the consideration on the WRE Acquisition that is due July 31, 2026.
Current report
Williston Basin Acquisition 2025. The acquisition in July 2025 of producing properties in the Williston Basin of Montana and North Dakota for approximately $331.6 million including the $70.0 million deferred payment that is due July 31, 2026.
Removed paragraphs (10)
Previous report
Mancos Shale Development
Previous report
The Mancos Shale is a large natural gas field, located in the San Juan Basin, where we hold an approximately 58,500 contiguous-acre position that is held by production. We have identified a 3,500-acre block as Phase I for developing and monetizing reserves, representing approximately 6% of our current Mancos position. Since our position is not subject to any leasehold expiration dates, we expect to develop this acreage at a measured pace as commodity prices allow. As of December 31, 2024, we do not have any proved reserves associated with our current Mancos position. Please see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
Previous report
Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we are subject) on corporations and other entities. While we do not pay income tax in Texas, we are subject to Texas franchise taxes.
Previous report
Results of Operations
Previous report
Williston Basin acquisitions. This increase was partially offset by decreased maintenance and energy costs on our historical properties.
Previous report
Taxes, transportation, and other decreased $15.0 million, or 20%, from $75.4 million for the year ended December 31, 2023 to $60.4 million for the year ended December 31, 2024. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices as well as decreased NGLs and natural gas volumes.
Previous report
Asset Retirement Obligation
Previous report
•Additional Interest Vacuum Acquisition. The acquisition in August 2022 of additional interest in our producing properties and a gas processing plant in the Permian Basin of New Mexico for approximately $52.8 million.
Previous report
Public company expenses
Previous report
We incurred in 2023 and 2024 and expect to incur in 2025 incremental costs related to our transition to a publicly traded partnership, including the costs associated with the initial implementation of our internal controls and testing. We also incurred additional significant and recurring expenses as a publicly traded partnership, including costs associated with the employment of additional personnel, compliance under the Exchange Act, annual and quarterly reports to unitholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. The direct, incremental general and administrative costs are not included in our historical financial statements prior to going public in January 2023.
Reworded paragraphs (46)
Previous wording
On June 28, 2024, we completed the Offering for the sale of 6.5 million common units at a price of $20.00 per common unit, which resulted in proceeds of $122.5 million net of underwriting discounts, commissions and other costs. On July 2, 2024, we completed the sale of an additional 975,000 common units at a price of $20.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional proceeds of $18.7 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the Williston Acquisitions.
Current wording
On May 15, 2025, we completed the 2025 Offering for the sale of 11,666,667 common units at a price of $15.00 per common unit resulting in net proceeds of approximately $165.6 million net of underwriting discounts, commissions and other costs (the "2025 Offering"). On May 19, 2025, we completed the sale of an additional 1,750,000 common units at a price of $15.00 per common unit pursuant to the underwriter's exercise in full of its option to purchase additional common units in the 2025 Offering, resulting in additional proceeds of approximately $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 WRE Acquisition.
Previous wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 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 and 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 declining to $72.73 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. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.
Current wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2023 through December 31, 2025, prices for crude oil and natural gas reached a high of $93.68 per Bbl and $5.29 per MMBtu, respectively, and a low of $55.27 per Bbl and $1.58 per MMBtu, respectively. Oil prices moderated during the first half of
Previous wording
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 since 2022, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate in 2024, 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 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.
Current wording
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. 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. 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.
Previous wording
Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile. During the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually. See “—Liquidity and Capital Resources—Revolving credit agreement.”
Current wording
Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile. During the period from January 1, 2023 through December 31, 2025, prices for crude oil and natural gas reached a high of $93.68 per Bbl and $5.29 per MMBtu, respectively, and a low of $55.27 per Bbl and $1.58 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually. See “—Liquidity and Capital Resources—Revolving credit agreement.”
Previous wording
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, most 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:
Current wording
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, the 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:
Previous wording
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. We have entered into basis swap agreements for a portion of our gas production that effectively fix the basis adjustment for our delivery locations.
Current wording
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. At times, we enter into basis swap agreements for a portion of our gas production that effectively fix the basis adjustment for our delivery locations.
Previous wording
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.
Current wording
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.
Previous wording
(a)Reductions to NYMEX gas price for delivery location
Current wording
Reductions to NYMEX gas price for delivery location
Previous wording
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.”
Current wording
General and administrative expenses consist primarily of personnel related costs and are partially offset by certain reimbursements of overhead expenses.
Previous wording
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 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.
Current wording
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.
Previous wording
(1)Oil and condensate prices include both realized and unrealized losses from derivatives. The unrealized gains were $5.8 million for the year ended December 31, 2024 and $9.5 million for the year ended December 31, 2023 and unrealized losses were $13.0 million for the year ended December 31, 2022. The realized losses were $5.6 million for the year ended December 31, 2024, $7.1 million for the year ended December 31, 2023 and $32.8 million for the year ended December 31, 2022.
Current wording
Oil and condensate prices include both realized and unrealized gains and losses from derivatives. The unrealized gains were $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, 2023. The realized gains were $7.1 million for the year ended December 31, 2025 and realized losses were $5.6 million for the year ended December 31, 2024 and $7.1 million for the year ended December 31, 2023.
Previous wording
(2)Natural gas liquids prices include both realized and unrealized losses from derivatives. The unrealized losses were $0.5 million for the year ended December 31, 2024, unrealized gains were $1.0 million for the year ended December 31, 2023 and unrealized losses were $1.0 million for the year ended December 31, 2022. The realized gains were $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.
Current wording
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 and unrealized gains were $1.0 million for the year ended December 31, 2023. The realized gains were $0.0 million for the year ended December 31, 2025 ,$0.5 million for the year ended December 31, 2024 and $0.4 million for the year ended December 31, 2023.
Previous wording
(3)Natural gas prices include both realized and unrealized losses from derivatives. The unrealized losses were $12.8 million for the year ended December 31, 2024, unrealized gains were $95.8 million for the year ended December 31, 2023 and unrealized losses were $99.2 million for the year ended December 31, 2022. The realized gains were $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.
Current wording
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 and unrealized gains were $95.8 million for the year ended December 31, 2023. The realized gains were $6.6 million for the year ended December 31, 2025 and $10.0 million for the year ended December 31, 2024 and realized losses were $76.4 million for the year ended December 31, 2023.
Previous wording
Revenues decreased $97.9 million, or 26%, from $380.7 million for the year ended December 31, 2023 to $282.8 million for the year ended December 31, 2024. The decrease 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 162 MBoe which resulted in increased revenue of $22.4 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 the average selling price, excluding the effects of derivatives, on NGLs of 8%, resulting in an increase in revenue of $2.2 million.
Current wording
Revenues increased $118.2 million, or 42%, from $282.8 million for the year ended December 31, 2024 to $401.0 million for the year ended December 31, 2025. The increase was primarily attributable to an increase in production of 1,758 MBoe which resulted in increased revenue of $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, the change in 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 oil of 16%, resulting in a decrease in revenue of $30.8 million and on NGLs of 12%, resulting in a decrease in revenue of $3.5 million.
Previous wording
Production expenses increased $5.6 million, or 4%, from $144.7 million for the year ended December 31, 2023 to $150.3 million for the year ended December 31, 2024. Of this increase, $10.0 million is attributable to production fromthe
Current wording
Production expenses increased $35.9 million, or 24%, from $150.3 million for the year ended December 31, 2024 to $186.2 million for the year ended December 31, 2025. Of this increase, $31.2 million is attributable to production from the Williston Basin acquisitions. Additionally, the increase was due to increased maintenance and personnel costs on our historical properties.
Previous wording
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. The increase is primarily related to the increased costs per Boe from our historical properties as decreased production more than offset decreased costs in these properties. This increase was partially offset by lower costs per Boe fromthe Williston Basin acquisitions.
Current wording
On a per unit basis, production expenses increased from $17.56 per Boe sold for the year ended December 31, 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 actual costs increased while production from our historical properties decreased. Additionally, costs were higher per Boe on our Williston Basin properties in 2025.
Previous wording
On a per unit basis, taxes, transportation, and other decreased from $8.98 per Boe sold for the year ended December 31, 2023 to $7.06 per Boe sold for the year ended December 31, 2024. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices.
Current wording
On a per unit basis, taxes, transportation, and other decreased from $7.06 per Boe sold for the year ended December 31, 2024 to $6.67 per Boe sold for the year ended December 31, 2025. The decrease is primarily attributable to the decrease in oil and NGL prices partially offset by increased natural gas prices.
Previous wording
Depreciation, depletion, and amortization increased $8.1 million, or 18%, from $44.3 million for the year ended December 31, 2023 to $52.4 million for the year ended December 31, 2024. The increase is primarily attributable to the increased production associated withthe Williston Basin acquisitions of $10.4 million which has a higher rate than the historical properties, partially offset by decreased production on our historical properties.
Current wording
Depreciation, depletion, and amortization increased $44.2 million, or 84%, from $52.4 million for the year ended December 31, 2024 to $96.6 million for the year ended December 31, 2025. The increase is primarily attributable to the increased production associated with the Williston Basin acquisitions of $38.4 million which has a higher rate than the historical properties and increased costs on our historical properties of $5.8 million, primarily due to changes in production mix.
Previous wording
On a per unit basis, depreciation, depletion, and amortization increased from $5.27 per Boe sold for the year ended December 31, 2023 to $6.12 per Boe sold for the year ended December 31, 2024. The increase is primarily related to the production associated withthe Williston Basin acquisitions which has a higher rate than the historical properties.
Current wording
On a per unit basis, depreciation, depletion, and amortization increased from $6.12 per Boe sold for the year ended December 31, 2024 to $9.36 per Boe sold for the year ended December 31, 2025. The increase is primarily related to the production associated with the Williston Basin acquisitions which has a higher rate than the historical properties as well as changes in production mix on our historical properties which resulted in higher costs per Boe.
Previous wording
We did not record an impairment of long-lived assets for the year ended December 31, 2024. We recorded an impairment of long-lived assets of$223.4 million for the year ended December 31, 2023. The impairment was related toour assets in the Texas Permian Basin, that is within our Cross Timbers joint venture, primarily due to a lower net commodity price environment and higher costs as well as a change in our development plans to reduce the duration of the proved undeveloped reserves from five years to two years.
Current wording
We recorded an impairment of long-lived assets of $42.4 million for the year ended December 31, 2025. The impairment was related to our assets in the Permian Basin, that is within our Cross Timbers joint venture, primarily due to lower oil prices and higher costs. We did not record an impairment of long-lived assets for the year ended December 31, 2024.
Previous wording
General and administrative (“G&A”) expenses increased $6.6 million, or 84%, from $7.9 million for the year ended December 31, 2023 to $14.5 million for the year ended December 31, 2024. The increase is primarily attributable to higher personnel costs of $4.8 million due in part to amortization of unit awards and additional expenses related to being a public company.
Current wording
General and administrative (“G&A”) expenses increased $6.9 million, or 48%, from $14.5 million for the year ended December 31, 2024 to $21.5 million for the year ended December 31, 2025. The increase is primarily attributable to higher personnel costs due in part to amortization of unit awards and higher professional fees.
Previous wording
On a per unit basis, G&A expense increased from $0.94 per Boe sold for the year ended December 31, 2023 to $1.70 per Boe sold for the year ended December 31, 2024. The increase is primarily related to increased costs partially offset by increased production.
Current wording
On a per unit basis, G&A expense increased from $1.70 per Boe sold for the year ended December 31, 2024 to $2.08 per Boe sold for the year ended December 31, 2025. The increase is primarily related to increased costs partially offset by increased production.
Previous wording
Other income increased $13.4 million, or 56%, from $23.8 million for the year ended December 31, 2023 to $37.2 million for the year ended December 31, 2024. The increase is primarily attributable to$9.7 millionin bonus receipts on term assignment of leases, higher CO 2 and plant income of$3.1 million and a$0.7 million increase in marketing income. The CO 2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO 2 assets in Colorado.
Current wording
Other income decreased $11.8 million, or 32%, from $37.2 million for the year ended December 31, 2024 to $25.3 million for the year ended December 31, 2025. The decrease is primarily attributable to the decreased bonus receipts on term assignment of leases of $6.7 million and lower CO 2 and plant income of $5.1 million as a result of third-party pipeline disruptions. The CO 2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO 2 assets in Colorado.
Previous wording
Interest expense increased $3.5 million, or 78%, from $4.4 million for the year ended December 31, 2023 to $7.9 million for the year ended December 31, 2024. The increase is primarily attributable to increased borrowings due tothe Williston Basin acquisitions and a higher interest rate.
Current wording
Interest expense increased $9.1 million, or 115%, from $7.9 million for the year ended December 31, 2024 to $17.0 million for the year ended December 31, 2025. The increase is primarily attributable to increased borrowings due to the Williston Basin Transactions partially offset by a lower interest rate.
Previous wording
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 $150.0 million at December 31, 2024 and $21.0 million at December 31, 2023, and the remaining availability under our Credit Facility was $125.0 million at December 31, 2024 and $144.0 million at December 31, 2023. Additionally, we had negative net working capital (including cash and excluding the effects of derivative instruments) of $2.5 million at December 31, 2024 and positive net working capital of $14.1 million at December 31, 2023.
Current wording
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 the remaining availability under our Credit Facility was $126.0 million at December 31, 2025 and $125.0 million at December 31, 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, 2024. The negative net working capital of $71.8 million at December 31, 2025 is primarily related to the $70.0 million deferred payment on the WRE Acquisition that is due July 31, 2026.
Previous wording
On June 28, 2024, we completed the Offering for the sale of 6.5 million common units at a price of $20.00 per common unit which resulted in proceeds of $122.5 million net of underwriting discounts, commissions and other costs. On July 2, 2024, we completed the sale of an additional 975,000 common units at a price of $20.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional proceeds of $18.7 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the Williston Acquisitions.
Current wording
On May 15, 2025, we completed the 2025 Offering for the sale of approximately 11,666,667 common units at a price of $15.00 per common unit resulting in net proceeds of approximately $165.6 million net of underwriting discounts, commissions and other costs. On May 19, 2025, we completed the sale of an additional 1,750,000 common units at a price of $15.00 per common unit pursuant to the underwriter's exercise in full of its option to purchase additional common units in the 2025 Offering, resulting in additional net proceeds of approximately $23.9 million, after deducting underwriting discounts, commissions and other costs. We used a portion of the proceeds from the 2025 Offering to fund a portion of the cash consideration for the WRE Acquisition.
Previous wording
Our net credit facility debt as of December 31, 2024 was $142.7 million (less cash of $7.3 million). These borrowings under our Credit Facility, which increased our net debt-to-EBITDAX ratio to approximately one times, were incurred to fund the remainder of the Williston Basin Acquisitions. We expect to carry this level of debt moving forward.
Current wording
Our net credit facility debt as of December 31, 2025 was $274.6 million (less cash of $9.4 million). These borrowings under our Credit Facility, which increased our net debt-to-EBITDAX ratio to between one and two, were incurred to fund the remainder of the Williston Basin Transactions. We expect to maintain this range of leverage moving forward.
Previous wording
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.
Current wording
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. 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.
Previous wording
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 per unit with respect to cash available for distribution for the three months ended December 31, 2024, was declared on March 04, 2025 and will be paid on March 21, 2025 to unitholders of record on March 14, 2025.
Current wording
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 $0.30 per unit with respect to cash available for distribution for the three months ended December 31, 2025, was declared on February 26, 2026 and will be paid on March 17, 2026 to unitholders of record on March 10, 2026.
Previous wording
Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $288.3 million for the year ended December 31, 2024 and $46.2 million for the year ended December 31, 2023.
Current wording
Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $335.3 million for the year ended December 31, 2025 and $288.3 million for the year ended December 31, 2024.
Previous wording
We incurred costs of approximately$28.0 million for drilling, completion and recompletion activities and facilities costs in 2024 and we have budgeted approximately$30 - $50 million for such costs in 2025. We expect to fund these capital expenditures from cash flow from operations.
Current wording
We incurred costs of approximately $71.1 million for drilling, completion and recompletion activities and facilities costs in 2025 and we have budgeted approximately $70 million for such costs in 2026. We expect to fund these capital expenditures from cash flow from operations.
Previous wording
Net cash provided by operating activities increased $32.1 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily as a result of increased production and lower expenses partially offset by lower oil and natural gas prices in 2024 compared to 2023.
Current wording
Net cash provided by operating activities increased $8.9 million for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily as a result of increased production and higher natural gas prices partially offset by higher expenses and lower oil prices in 2025 compared to 2024.
Previous wording
Net cash used by investing activities increased $242.1 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 due to an increase 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 million.
Current wording
Net cash used by investing activities increased $47.0 million for the year ended December 31, 2025 compared to the year ended December 31, 2024 due to an increase in development costs of $48.5 million partially offset by a decrease in proved property and other property acquisitions of $1.5 million.
Previous wording
Net cash provided by financing activities increased $217.4 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 due to an increase in net borrowings under our credit facility of $221.0 million and increased proceeds from public offerings of$35.0 million partially offset by increased distributions to unitholders of$35.6 millionand increased debt offering costs of$3.0 million.
Current wording
Net cash provided by financing activities increased $37.4 million for the year ended December 31, 2025 compared to the year ended December 31, 2024 due to increased proceeds from public offerings of $48.3 million and an increase in net borrowings under our credit facility of $5.0 million partially offset by increased distributions to unitholders of $16.1 million.
Previous wording
On August 30, 2024, we entered into Amendment No. 4 and Borrowing Base Agreement (“Amendment No. 4”) on our senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 4 extended the maturity date of the Credit Facility to August 30, 2028, increased the borrowing base from $165 million to $275 million and joined certain new Lenders to the Credit Facility. Our Credit Facility permits us to use proceeds for general partnership purposes including distributions to our unitholders. Our obligations under the Credit Facility are secured by substantially all of our assets, including (i) our interest in Cross Timbers, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by us and our wholly-owned subsidiaries. In connection with entering into the Credit Facility, as of December 31, 2024, we incurred financing fees and expenses of approximately $6.2 million before accumulated amortization of $2.5 million. These costs are being amortized over the life of the Credit Facility. We incurred $3.1 million of financing fees and expenses in conjunction with Amendment No. 4. Such amortized expenses are recorded as interest expense on the statements of operations. As of December 31, 2024, we had $150 million in borrowings outstanding under our Credit Facility and $125 million in availability.
Current wording
On July 31, 2025, we entered into Amendment No. 5 and Borrowing Base Agreement (“Amendment No. 5”) on our senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 5 extended the maturity date of the Credit Facility to August 30, 2029, increased the borrowing base from $275 million to $410 million and joined certain new Lenders to the Credit Facility. Our Credit Facility permits us to use proceeds for general partnership purposes including distributions to our unitholders. Our obligations under the Credit Facility are secured by substantially all of our assets, including (i) our interest in Cross Timbers, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by us and our wholly-owned subsidiaries. In connection with entering into the Credit Facility, as of December 31, 2025, we incurred financing fees and expenses of approximately $8.6 million before accumulated amortization of $3.6 million. These costs are being amortized over the life of the Credit Facility. We incurred $2.4 million of financing fees and expenses in conjunction with Amendment No. 5. Such amortized expenses are recorded as interest expense on the statements of operations. As of December 31, 2025, we had $284.0 million in borrowings outstanding under our Credit Facility and $126.0 million in availability.
Previous wording
At our election, interest on borrowings under the Credit Facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the aggregate commitments under the Credit Facility minus the aggregate outstanding principal amount of all advances at such time. The weighted average interest rate on Credit Facility borrowings was 8.6% in 2024. The effective borrowing rate under our Credit Facility was 8.3% as of December 31, 2024.
Current wording
At our election, interest on borrowings under the Credit Facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the aggregate commitments under the Credit Facility minus the aggregate outstanding principal amount of all advances at such time. The weighted average interest rate on Credit Facility borrowings was 7.9% in 2025. The effective borrowing rate under our Credit Facility was 7.6% as of December 31, 2025.
Previous wording
We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio (“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Effective with the Second Amendment entered in June 2023 (the “Second Amendment”), our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required tohedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of December 31, 2024 and December 31, 2023. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.
Current wording
We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio (“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Effective with the Second Amendment entered in June 2023 (the “Second Amendment”), our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required to hedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of December 31, 2025 and December 31, 2024. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.
Previous wording
Our Credit Facility permits us to make distributions of 100% of our “Distributable Cash Flow” so long as (i) at the time of any such distribution and immediately after giving effect thereto, no default, event of default or borrowing base deficiency has occurred and is continuing, (ii) the our ratio of total net debt-to-EBITDAX does not exceed 2.00 to 1.00 as of the last day of the fiscal quarter most recently ended for which our financial statements have been delivered (determined on a pro forma basis after giving effect to such distribution) and (iii) after giving effect to such distribution, there is at least 20% of total borrowings then available under our Credit Facility. For purposes of our Credit Facility, “Distributable Cash Flow” is defined, generally, to mean (a) our EBITDAX during each period of four consecutive quarters (a “rolling period”), minus the increase (or plus the decrease) in working capital from the previous rolling period minus (b) the sum of (i) capital expenditures paid in cash, (ii) cash interest expense, (iii) cash taxes paid, (iv) exploration expenses or costs paid in cash, (v) restricted payments made in cash (other than any prior distributions of Distributable Cash Flow) and (vi) to the extent not included in this clause (b) and otherwise added back in the calculation of EBITDAX, any other cash charge that reduces our earnings. The amount of Distributable Cash Flow with respect to any fiscal quarter is further reduced by all prior distributions of Distributable Cash Flow during the applicable rolling period.
Current wording
Our Credit Facility permits us to make distributions of 100% of our “Distributable Cash Flow” so long as (i) at the time of any such distribution and immediately after giving effect thereto, no default, event of default or borrowing base deficiency has occurred and is continuing, (ii) the ratio of total net debt-to-EBITDAX does not exceed 2.25 to 1.00 as of the last day of the fiscal quarter most recently ended for which our financial statements have been delivered (determined on a pro forma basis after giving effect to such distribution) and (iii) after giving effect to such distribution, there is at least 20% of total borrowings then available under our Credit Facility. For purposes of our Credit Facility, “Distributable Cash Flow” is defined, generally, to mean (a) our EBITDAX during each period of four consecutive quarters (a “rolling period”), minus the increase (or plus the decrease) in working capital from the previous rolling period minus (b) the sum of (i) capital expenditures paid in cash, (ii) cash interest expense, (iii) cash taxes paid, (iv) exploration expenses or costs paid in cash, (v) restricted payments made in cash (other than any prior distributions of Distributable Cash Flow) and (vi) to the extent not included in this clause (b) and otherwise added back in the calculation of EBITDAX, any other cash charge that reduces our earnings. The amount of Distributable Cash Flow with respect to any fiscal quarter is further reduced by all prior distributions of Distributable Cash Flow during the applicable rolling period.
Previous wording
We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2024, the current liability related to such contracts was $5.8 million and the non-current liability was $8.0 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas.
Current wording
We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2025, the current liability related to such contracts was $5.1 million and the non-current liability was less than $0.1 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas.
Previous wording
At December 31, 2024, we had asset retirement obligations of $190.9 million inclusive of a current portion of $2.0 million. For further information on asset retirement obligations, see Note 7 in the financial statements included in Item 8. Financial Statements and Supplementary Data.
Current wording
At December 31, 2025, we had asset retirement obligations of $221.1 million inclusive of a current portion of $3.5 million. For further information on asset retirement obligations, see Note 7 in the financial statements included in Item 8. Financial Statements and Supplementary Data.
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Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
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 and continued throughout 2025, as OPEC unwound previous output cuts which lead to rising oil inventories. Oil prices were to $65.21 per Bbl as of January 30, 2026. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations