What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-24 compared with 2025-02-25 · 114 added, 106 removed, 266 unchanged (45% of the section changed)

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We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest.

We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured.

Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

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Development Activity

Currently, EXCO Resources, Inc.

is operating one rig and Aethon is operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.

During 2025, Aethon has already turned-to-sales (“TTS”) 11 gross (0.9 net) wells with early data showing better performance than the older offsets and initial rates primarily between 20 – 30 MMcf/d.

We expect Aethon to continue its development program under the amended JEAs with an estimated 17 gross (1.1 net) additional wells TTS during 2025.

In the Louisiana Haynesville during 2024, we entered into several Accelerated Drilling Agreements (“ADAs”) with large, well-capitalized operators.

Under these agreements, the operators will provide near term certainty and accelerated development on our high-interest areas in exchange for a reduced royalty burden.

During 2024, 2 gross (0.4 net) wells were TTS and we expect an additional 11 gross (0.6) net wells to TTS in 2025.

In the Permian Basin, a large producer is expected to begin development of over 37 gross (1.3 net) wells in Culberson County, Texas, which includes 8 gross wells to be TTS in the fourth quarter of 2025.

Farmout Agreements

In September and December 2024, two of our farmout agreements covering non-operated working interests in San Augustine County terminated.

Consistent with our policy to minimize participation in working interests, we do not intend to step into the working interests associated with the terminated agreements.

Unless we agree otherwise with Aethon, we believe that Aethon, as operator and the party who has proposed the existing wells, has absorbed and will continue to absorb any non-consented interests.

During the fourth quarter, Aethon was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.

Aethon’s development program remains on track, with 6 wells spud in the second half of 2025 as part of the current program year ending June 30, 2026, an additional 8 wells expected in the first half of 2026 to complete that program year, and 10 more wells expected in the second half of 2026 as part of the next program year.

Aethon successfully turned to sales 7 gross (0.42 net) wells during the fourth quarter and has an inventory of 5 gross (0.31 net) wells from the previous program year that it expects to turn to sales during early 2026.

Our agreement with Revenant covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres.

Revenant is obligated to drill a minimum of 6 wells in 2026, increasing annually to a minimum of 25 wells per year by 2030.

We also secured a non-operated working interest partner for the development.

In November 2025, the agreement was amended to maintain the 6-well commitment for 2026 and convert future commitments to completed gross lateral-foot targets at one well per 7,000 lateral feet, allowing longer laterals while keeping overall development levels unchanged.

Revenant expects to spud more wells than its 6-well commitment for the first program year ending December 31, 2026.

In November 2025, we entered into a 220,000 gross acre development agreement with Caturus, which aims to push the Shelby Trough westward towards the Western Haynesville.

Activity will begin with approximately 2 gross (0.2 net) wells in 2026 and ramp to approximately 12 gross (0.8 net) wells annually by 2031, supported by minimum annual lateral-foot requirements, all net to our interest.

In addition to the 2 gross wells in 2026, Caturus plans to drill a pilot well stepping out towards Houston County, consistent with the terms of the agreement.

For additional information about our Shelby Trough development agreements, please read Part I, Items 1.

“Business and Properties—Our Assets—Shelby Trough Development Agreements”.

In the Permian Basin, Coterra Energy continues to develop our acreage in Culberson County, Texas.

During the third quarter, 5 gross wells (0.17 net) were turned to sales, with the remaining 34 gross (1.21 net) wells expected in the first half of 2026.

A second large development of 30 gross (2.04 net) wells in the southern Delaware Basin is expected to come online in the second half of 2026 and first half of 2027.

Acquisition Activity

In the fourth quarter of 2025, we acquired $48.8 million of additional (primarily non-producing) mineral and royalty interests.

From September 2023 through December 2025, we have completed $239.5 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.

Business Environment

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Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand.

To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.

Oil prices rose in early 2024 due to heightened geopolitical risks, including attacks on vessels in the Red Sea and elevated tensions in the region, but declined later in the year due to market oversupply concerns.

Natural gas prices decreased sharply in late 2023 and early 2024 due to surplus storage but increased in the second quarter of 2024 due to reduced drilling and production curtailments.

This upward trend continued into the third and fourth quarters, driven by high energy demand from extreme temperatures and increased LNG exports.

Given the dynamic nature of these events, along with the geopolitical conflicts in Ukraine and the Middle East, we cannot reasonably estimate how long these market conditions will persist.

Oil prices decreased during the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased global supply and uncertainty about the outlook for global economic growth and oil demand.

Supply growth from both OPEC+ and non-OPEC+ producers contributed to higher global inventories during the year, placing downward pressure on crude oil prices.

Natural gas prices increased during the year ended December 31, 2025 relative to the prior-year period.

Colder-than-normal weather during the first quarter increased heating demand and reduced storage levels, while higher demand for power generation during the summer months also contributed to higher natural gas prices.

In addition, continued growth in LNG export demand further strengthened market conditions.

In the fourth quarter of 2025, natural gas prices rose, driven by seasonal heating demand, continued LNG export demand, and relatively tight storage levels.

Given the dynamic nature of commodity markets, we cannot reasonably estimate how long current price levels or market conditions will persist.

While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

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Natural Gas Storage

A substantial portion of our revenue is derived from sales of oil production attributable to our interests;

however, the majority of our production is natural gas.

The majority of the production volumes attributable to our interests is derived from natural gas production.

Natural gas prices are significantly influenced by storage levels throughout the year.

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The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.

The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025, at 1.9 Tcf, or 1% higher than the five-year average.

The EIA expects inventories will rise to 3.7 Tcf at the end of October 2025, which would be 2% lower than the five-year average.

The EIA forecasts that inventories will conclude the withdraw al season, which is the end of March 2026, at 1.8 Tcf, or 2% higher than the five-year average.

The EIA expects inventories will rise to 3.8 Tcf at the end of October 2026, which would be 5% higher than the five-year average.

The following table shows natural gas storage volumes by region at the end of each quarter presented:

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Natural Gas Exports

Net natural gas exports averaged 12.0 Bcf per day during 2024, a 1% increase from the 2023 average.

The EIA forecasts average exports of 14.1 Bcf per day for the start of 2025, an 18% increase from 2024 levels.

Net natural gas exports avera ged 15.0 Bcf per day during 2025, a 26% incr ea se from the 2024 average.

The EIA forecasts average exports of 16.4 Bcf per day for the start of 2026, a 9% increase from 2025 levels.

The EIA forecast reflects assumptions that U.S.

LNG exports will increase as new LNG export projects begin operations in mid-2025.

LNG exports will increase as new LNG export projects begin operations in 2026.

How We Evaluate Our Operations

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Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

Although the growth in LNG export capacity and global shipping has increased connectivity among certain markets, transportation remains infrastructure-dependent and subject to capacity constraints, and prices may continue to vary by region.

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.

From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements.

Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price.

Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price.

If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts.

Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price.

Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price.

If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations.

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Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed, but not required, to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

We are allowed, but not required, to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

As of December 31, 2025, we had hedged 93% and 27% of our available oil and condensate hedge volumes and 100% and 54% of our available natural gas hedge volumes for 2026 and 2027, respectively.

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Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, seismic data acquisition costs, non-cash equity-based compensation, unrealized gains and losses on commodity derivative instruments, and gains and losses on sales of assets, if any.

We define Distributable Cash Flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

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

Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations.

Comparative amounts for the year ended December 31, 2024 for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation.

Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests.

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

as measures of our financial performance.

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Our computation of Adjusted EBITDA and Distributable Cash Flow may differ from computations of similarly titled measures of other companies.

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

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

Year Ended December 31,

(in thousands)

Net income (loss) $ 271,326 $ 422,549

Net income $ 299,932 $ 271,326

Adjustments to reconcile to Adjusted EBITDA:

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Accretion of asset retirement obligations 1,374 1,298

Seismic data acquisition costs 17,349 2,287

Equity-based compensation 9,620 8,564

Unrealized (gain) loss on commodity derivative instruments (36,602) 50,944

(Gain) loss on sale of assets, net — (73)

Adjusted EBITDA 337,353 383,233

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however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Total revenue for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023.

The decrease in total revenue from the corresponding period is due to lower oil and condensate sales, lower natural gas and NGL sales, and a loss on commodity derivative instruments in 2024 compared to a gain in 2023.

Total revenue for the year ended December 31, 2025 increased compared to the year ended December 31, 2024.

The increase in total revenue from the corresponding period is due to higher natural gas and NGL sales, higher lease bonus and other income and a gain on commodity derivative instruments in 2025 compared to a loss in 2024.

Lower oil revenues, resulting from reduced production and commodity prices, partially offset the overall increase in total revenue.

Oil and condensate sales.

Oil and condensate sales decreased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to lower realized commodity prices and lower production volumes.

The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Eagle Ford play trends.

The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Permian Basin play trends.

Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for the years ended December 31, 2025 and 2024, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Haynesville/Bossier play trends.

Natural gas and NGL sales increased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to higher realized commodity prices partially offset by lower production volumes.

The decrease in natural gas and NGL production was driven by decreased production volumes in the Austin Chalk and Haynesville/Bossier play trends.

Mineral and royalty interest production accounted for 96% and 95% of our natural gas volumes for the years ended December 31, 2025 and 2024, respectively.

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The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

During 2024, we recognized $45.2 million of realized gains and $50.9 million of unrealized losses from our commodity derivatives, compared to $82.7 million of realized gains and $8.4 million of unrealized gains in 2023.

The unrealized losses on our commodity contracts in 2024 and the unrealized gains in 2023 were primarily driven by changes in the forward commodity price curves for natural gas.

During 2025, we recognized $11.0 million of realized gains and $36.6 million of unrealized gains from our commodity derivatives, compared to $45.2 million of realized gains and $50.9 million of unrealized losses in 2024.

The unrealized gains on our commodity contracts in 2025 were driven equally by changes in the forward commodity price curves for both natural gas and oil while the unrealized losses in 2024 were primarily driven by changes in the forward commodity price curves for natural gas.

Lease bonus and other income .

When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus.

Lease bonus income can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant.

Lease bonus and other income was slightly lower for the year ended December 31, 2024, as compared to 2023.

Leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays made up the majority of lease bonus and other income for 2024, while the majority of our 2023 lease bonus and other income came from leasing activity in the Haynesville/Bossier and Wolfcamp plays.

Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant.

Lease bonus and other income was higher for the year ended December 31, 2025, as compared to 2024.

Leasing activity in the Wolfcamp, Bakken/Three Forks, and Haynesville/Bossier plays made up the majority of lease bonus and other income for 2025, while the majority of our 2024 lease bonus and other income came from leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development.

Operating Expenses

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Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs.

Lease operating expense decreased in 2024 as compared to 2023, due to a reduction in variable costs as a result of lower production from our non-operated working interest properties and lower nonrecurring service-related expenses, including workovers.

Lease operating expense increased slightly in 2025 as compared to 2024, due to higher nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes.

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Rates, methods of calculating property values, and timing of payments vary between taxing authorities.

For the year ended December 31, 2024, production and ad valorem taxes decreased as compared to the year ended December 31, 2023, primarily due to a decrease in production taxes and processing and transportation costs stemming from lower commodity prices and decreased production volumes.

For the year ended December 31, 2025, production and ad valorem taxes decreased as compared to the year ended December 31, 2024, primarily due to a decrease in production taxes and processing and transportation costs stemming from decreased production volumes, as well as lower ad valorem tax estimates.

Exploration expense.

Exploration expense typically consists of dry-hole expenses, payments for delay rentals where we are the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.

Exploration expense was higher in 2024 as compared to 2023, primarily due to an increase in seismic costs and delay rentals.

Exploration expense was significantly higher in 2025 as compared to 2024, primarily driven by purchases of seismic data and costs from proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough area.

Depreciation, depletion, and amortization.

Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis.

Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis.

Estimates of proved developed producing reserves are a major component of the calculation of depletion.

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General and administrative.

General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services.

For the year ended December 31, 2024, general and administrative expenses slightly increased compared to 2023, primarily due to increases in salaries, software related expenses, and consulting costs for internal projects;

these costs were partially offset by a decrease in equity based compensation and expenses associated with the use of contractors.

The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2024 compared to upward movements in our common unit price during 2023.

General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services.

For the year ended December 31, 2025, general and administrative expenses slightly increased compared to 2024, primarily due to higher salaries of $1.4 million driven by increased headcount and inflation, higher software-related expenses of $1.2 million, and higher equity-based compensation of $1.2 million.

The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards driven by changes in our common unit price during 2025, compared to 2024.

These increases were partially offset by a $0.6 million decrease in consulting costs for internal projects.

Other Expense

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Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility.

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility as applicable, and for investing in our business.

On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date").

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business.

The distribution rate for the Series B cumulative convertible preferred units adjusted November 28, 2023 and will be readjusted every two years thereafter (each, a "Readjustment Date").

The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum.

We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023.

The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025.

We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value.

On August 21, 2025, we entered into an agreement with the holders of the Series B cumulative converted preferred units under which we agreed not to exercise our redemption option and the holders agreed to vote in accordance with Board recommendations and comply with customary transfer and standstill restrictions through November 27, 2027, with the next redemption window opening on November 28, 2027.

Depending on market conditions among other factors, we may use funds from the future issuance of common units or other equity securities or debt to redeem some or all of the preferred units.

See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

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We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt.

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

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

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis.

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Cash provided by operating activities for 2025 decreased as compared to 2024.

The decrease was primarily due to a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue, and a decrease in cash received on settlements of commodity derivative instruments.

The decrease was primarily due to reduced oil sales due to lower realized oil prices and production, and lower amounts of cash received from the settlement of commodity derivatives.

The overall decrease was partially offset by higher natural gas and NGL sales due to higher realized natural gas prices in 2025 compared to the same period in 2024.

Investing Activities .

Net cash used in investing activities for 2024 increased as compared to 2023.

The change was primarily due to increased acquisition activity in 2024 compared to the same period in 2023.

Net cash used in investing activities for 2025 slightly increased as compared to 2024.

The increase was primarily due to higher additions to oil and natural gas properties leasehold costs in 2025 compared to the same period in 2024.

Financing Activities .

Cash flows used in financing activities for 2024 decreased as compared to 2023.

The decrease was primarily due to lower distributions paid to common unitholders partially offset by net borrowings under our Credit Facility in 2024 compared with net repayments in 2023.

Net cash used in financing activities for 2025 decreased as compared to 2024.

The decrease was primarily due to lower distributions paid to unitholders and higher borrowings net of repayments under our Credit Facility in 2025 compared to 2024.

Development Capital Expenditures

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The timing, size, and nature of acquisitions are unpredictable.

Our 2025 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million.

The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest.

Expenditures related to drilling, completion, and recompletion costs for our non-operated working interests were $0.6 million and $0.8 million during 2025 and 2024, respectively.

Additionally, we spent $11.1 million and $3.4 million acquiring leases in areas around our drilling programs during 2025 and 2024, respectively.

Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

During 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $114.5 million, including capitalized direct transaction costs.

The consideration paid consisted of $107.1 million in cash that was funded from operating activities and $7.4 million in equity that was funded through the issuance of our common units based on the fair values of the common units issued on the acquisition dates.

These acquisitions were considered asset acquisitions and were primarily located in East Texas, within the Haynesville expansion area.

During 2024 we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs.

The cash portion of the consideration paid of $109.4 million was funded with borrowings under our Credit Facility and funds from operating activities, and $1.0 million was funded through the issuance of our common units based on the fair values of the common units issued on the acquisition dates.

These acquisitions were considered asset acquisitions and were primarily located in the Gulf Coast land region.

Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

During 2023 we acquired mineral and royalty interests for cash consideration of $14.6 million, including capitalized direct transaction costs.

The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region.

These acquisitions were considered asset acquisitions and were primarily located in East Texas, within the Haynesville expansion area.

See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Asset Exchange

In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

We completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.

These transactions, which are described below, involved partial dispositions of unproved property, and no gains or losses were recognized.

In March 2025, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.

In February 2025, we closed on a transaction with a third-party operator whereby we exchanged oil and natural gas leases covering certain acreage in East Texas.

We acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres.

In July 2024, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

Credit Facility

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The amount of the borrowing base is redetermined semi-annually, usually in April and October.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million.

The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024.

After each redetermination we elected to maintain cash commitments at $375.0 million.

We reaffirmed the borrowing base in April 2024, November 2024 and April 2025 at $580.0 million.

In October 2025, we amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and remove the adjustment applied to secured overnight financing rate ("SOFR") loans.

Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was reaffirmed at $580.0 million and we elected to maintain cash commitments under the Credit Facility at $375.0 million.

All existing banks in the lender syndicate elected to continue participating in the Credit Facility.

No other significant terms were changed as part of the amendment.

The next semi-annual redetermination is scheduled for April 2026.

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See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Contractual Obligations

The following table summarizes our minimum payments as of December 31, 2024 (in thousands):

Payments due by period

Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years

Credit facility $ 25,000 $ — $ 25,000 $ — $ —

Operating lease obligations 2,041 1,436 573 32 —

Purchase commitments 420 420 — — —

Total $ 27,461 $ 1,856 $ 25,573 $ 32 $ —

Critical Accounting Policies and Related Estimates

Material Cash Requirements

Our material cash requirements consist primarily of production costs and ad valorem taxes, general and administrative expenses, including payroll and benefits, office lease commitments, settlements under our commodity derivative contracts, and lease operating expenses and asset retirement obligations associated with our non-operated working interests.

We cannot provide specific timing for repayments of borrowings or associated interest under our Credit Facility, as such amounts depend on working capital requirements, commodity prices, and acquisition and divestiture activity.

Similarly, the timing and amount of other obligations, including asset retirement obligations and settlements under commodity derivative contracts, cannot be forecasted with certainty.

The fair value of our derivative contracts as of December 31, 2025 reflects the estimated cash settlement amount required to terminate such instruments based on forward commodity price curves as of that date.

See "Note 6 – Fair Value Measurements" for additional information.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP.

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Actual results could differ from those estimates.

Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas.

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Our reserve estimates are determined by an independent petroleum engineering firm.

subject to estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards.

We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions.

A significant decline in oil or natural gas prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties are impaired.

A significant decline in oil or natural gas prices could cause us to perform analyses to determine if our oil and natural gas properties are impaired.

As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.

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DD&A expense related to our producing oil and natural gas properties was $35.7 million, $44.8 million, and $45.0 million for the years ended December 31, 2025, 2024, and 2023, respectively.

We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

This evaluation is performed on a depletable unit basis.

We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability.

When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value.

The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

We evaluate impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

See "Note 6 - Fair Value Measurements" for additional information.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss.

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Applying this discount results in an approximate 1% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2025 reserve report prepared by NSAI.

Revenues from Contracts with Customers

Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified.

Oil and natural gas sales

Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured.

Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

The price we receive for natural gas is tied to

a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies.

As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.

We record oil and natural gas revenue in the month production is delivered to the purchaser.

As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered.

As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product.

The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets.

The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

We have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Accrued Revenues

We record revenue in the month production is delivered to the purchaser.

As a non-operator, we have limited visibility into the timing of when new wells begin producing, and production statements may not be received for 30 to 90 days or more after production is delivered.

As a result, a portion of revenue for each period is accrued and recorded in the line item Accrued revenue and accounts receivable on the consolidated balance sheets.

Accrued revenues are estimated using historical production data, adjusted for expected production declines, and projected sales prices, including applicable pricing adjustments.

Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the operator.

We review historical production, pricing assumptions, and the accuracy of prior accruals to ensure that the recorded amounts appropriately reflect revenues expected to be collected.

New and Revised Financial Accounting Standards

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis