Black Stone Minerals LP

Previous wording

As of December 31, 2023, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 68,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer 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.

Current wording

As of December 31, 2024, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer 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.

Previous wording

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2024, at 1.9 Tcf, or 15% higher than the five-year average. The EIA expects inventories will rise to 4.0 Tcf at the end of October 2024, which would be 6% higher than the five-year average.

Current wording

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA forecasts that inventories will conclude the 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.

Previous wording

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. As of December 31, 2023, we had hedged 73% of our available oil and condensate hedge volumes and 66% of our available natural gas hedge volumes for 2024.

Current wording

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. As of December 31, 2024, we had hedged 77% and 24% of our available oil and condensate hedge volumes and 82% and 69% of our available natural gas hedge volumes for 2025 and 2026, respectively.

Previous wording

Total revenue for the year ended December 31, 2023 decreased compared to the year ended December 31, 2022. The decrease in total revenue from the corresponding period is primarily due to lower realized commodity prices partially offset by an increase in production volumes and a gain on commodity derivative instruments in 2023 compared to a loss in 2022.

Current wording

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.

Previous wording

Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2023 were lower than the corresponding period in 2022 due to lower realized commodity prices partially offset by higher production volumes. The increase in oil and condensate production was primarily due to increased production volumes in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for each of the years ended December 31, 2023 and 2022, respectively.

Current wording

Oil and condensate sales. Oil and condensate 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 oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Eagle Ford play trends. Our mineral and royalty interest oil and condensate volumes accounted for 95% and 94% of total oil and condensate volumes for the years ended December 31, 2024 and 2023, respectively.

Previous wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to lower realized commodity prices offset by higher production volumes. The increase in natural gas and NGL production was driven by new development in the Haynesville/Bossier play trend, including new activity from the Aethon development program in the Shelby Trough. Mineral and royalty interest production accounted for 94% and 92% of our natural gas volumes for the years ended December 31, 2023 and 2022, respectively.

Current wording

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. Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the years ended December 31, 2024 and 2023, respectively.

Previous wording

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During 2023, we recognized $82.7 million of realized gains and $8.4 million of unrealized gains from our commodity derivatives, compared to $203.2 million of realized losses and $82.5 million of unrealized gains in 2022. The unrealized gains on our commodity contracts in 2023 were primarily driven by changes in the forward commodity price curves for natural gas and in 2022 by changes in the forward commodity price curves for both oil and natural gas.

Current wording

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During 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.

Previous wording

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, 2023, as compared to the same period in 2022. Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income in 2023 and 2022.

Current wording

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.

Previous wording

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased in 2023 as compared to 2022, primarily due to a reduction in variable costs as a result of lower production from our non-operated working interest properties.

Current wording

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

Previous wording

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the year ended December 31, 2023, production and ad valorem taxes decreased as compared to the year ended December 31, 2022, as a result of lower commodity prices.

Current wording

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the year ended December 31, 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.

Previous wording

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for 2023 significantly increased due to costs incurred to acquire seismic information related to our mineral and royalty interests.

Current wording

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.

Previous wording

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. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2023 as compared to 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities. The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months.

Current wording

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. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2024 as compared to 2023, primarily due to lower production volumes.

Previous wording

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, 2023, general and administrative expenses decreased compared to 2022, primarily due to a $6.6 million decrease in equity-based compensation from lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2023 compared to upward movements in our common unit price during 2022. The overall decrease was partially offset by increases in consulting costs of $2.6 million related to internal projects and a non-recurring $2.1 million recovery in allowance against an outstanding long-term receivable in 2022.

Current wording

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.

Previous wording

Interest expense. For the year ended December 31, 2023, interest expense decreased compared to 2022, primarily due to lower average outstanding borrowings resulting from fully paying down our Credit Facility in the first quarter of 2023. Interest expense in 2023 consisted primarily of commitment fees and amortization of debt issuance costs.

Current wording

Interest expense. For the year ended December 31, 2024, interest expense increased compared to 2023, primarily due to higher average outstanding borrowings under our Credit Facility.

Previous wording

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. 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 until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value. Thereafter, we may redeem the preferred units at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023. See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Current wording

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

Previous wording

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Current wording

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. As of December 31, 2024, we had not made any repurchases under the program.

Previous wording

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash provided by operating activities for 2023 increased as compared to 2022. The increase was primarily due to an increase in net cash received on settlements of commodity derivative instruments in 2023 compared to net cash paid in the same period of 2022. The overall increase was partially offset by a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue due to lower realized commodity prices.

Current wording

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash provided by operating activities for 2024 decreased as compared to 2023. 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.

Previous wording

Investing Activities. Net cash used in investing activities for 2023 increased as compared to 2022. The change was primarily due to increased acquisition activity and higher net oil and natural gas capital expenditures in 2023 compared to the same period in 2022.

Current wording

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.

Previous wording

Financing Activities. Cash flows used in financing activities for 2023 increased as compared to 2022. The increase was primarily due to higher distributions paid to common unitholders partially offset by lower net repayments under our Credit Facility in 2023 compared with 2022.

Current wording

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.

Previous wording

During the year ended December 31, 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. Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

Current wording

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.

Previous wording

We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in October and April. In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027, increased the borrowing base to $550.0 million and elected to lower commitments under the Credit Facility to $375.0 million. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $580.0 million. After both redeterminations we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2024.

Current wording

We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. 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. The next semi-annual redetermination is scheduled for April 2025.

Previous wording

We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

Current wording

We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred.

Previous wording

As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $45.0 million, $47.2 million, and $60.4 million for the years ended December 31, 2023, 2022, and 2021, respectively.

Current wording

As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $44.8 million, $45.0 million, and $47.2 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Previous wording

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. There was no impairment of proved oil and natural gas properties for the years ended December 31, 2023, 2022, and 2021.

Current wording

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.

Previous wording

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. There was no impairment of unproved properties for the years ended December 31, 2023, 2022, and 2021.

Current wording

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.

Previous wording

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded.

Current wording

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded.

Previous wording

We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2023 reserve report. Applying this discount results in an approximate 2.0% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2023 reserve report prepared by NSAI.

Current wording

We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2024 reserve report. Applying this discount results in an approximate 1.5% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2024 reserve report prepared by NSAI.

Previous wording

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. For the years ended December 31, 2023 and 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

Current wording

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.