Phoenix Energy One, LLC

Previous wording

(b)Use of Proceeds: On May 14, 2025, the registration statement with respect to up to $750.0 million aggregate principal amount of Registered Notes (File No. 333-282862) was declared effective and the Company commenced the offering of the Registered Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Registered Notes is ongoing, and, as of the date of this Quarterly Report, the Company has sold $80.0 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.5 million and transaction fees and expenses. The proceeds of the Registered Notes have been and will continue to be used as described in the prospectus with respect to the offering. On July 7, 2026, the registration statement with respect to up to $100.0 million aggregate principal amount of Phoenix Flex Junior Secured Notes (File No. 333-296428) was declared effective and the Company commenced the offering of the Phoenix Flex Junior Secured Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Phoenix Flex Junior Secured Notes is ongoing, and, as of the date of this Quarterly Report, the Company has not sold any Phoenix Flex Junior Secured Notes. The proceeds of the Phoenix Flex Junior Secured Notes will be used as described in the prospectus with respect to the offering.

Current wording

(b)Use of Proceeds: On May 14, 2025, the registration statement with respect to up to $750.0 million aggregate principal amount of Registered Notes (File No. 333-282862) was declared effective and the Company commenced the offering of the Registered Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Registered Notes is ongoing, and, as of the date of this Quarterly Report, the Company has sold $104.3 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.6 million and transaction fees and expenses. The proceeds of the Registered Notes have been and will continue to be used as described in the prospectus with respect to the offering.

Previous wording

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of June 30, 2026, we owned mineral, royalty, and working interests in 8,615 productive wells, the majority of which are oil wells that also produce natural gas and NGL.

Current wording

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of September 30, 2026, we owned mineral, royalty, and working interests in 8,843 productive wells, the majority of which are oil wells that also produce natural gas and NGL.

Previous wording

As of June 30, 2026, we had 220 wells that fall under our “wells in progress” (“WIP”) category, and we had 46.7 net WIP. We define a WIP as a development well in a stage preliminary to production. We utilize both proprietary and public systems to identify WIPs based on four distinct criteria: (i) a well that is not actively being drilled but is in the process of being developed; (ii) a well currently being drilled and awaiting completion; (iii) a drilled well in the completion process; and (iv) a drilled well that has been completed but is not yet producing. This term serves as a guide in our acquisition strategy, enabling us to pinpoint lower-risk investment opportunities for our stakeholders.

Current wording

As of September 30, 2026, we had 241 wells that fall under our “wells in progress” (“WIP”) category, and we had 56.6 net WIP. We define a WIP as a development well in a stage preliminary to production. We utilize both proprietary and public systems to identify WIPs based on four distinct criteria: (i) a well that is not actively being drilled but is in the process of being developed; (ii) a well currently being drilled and awaiting completion; (iii) a drilled well in the completion process; and (iv) a drilled well that has been completed but is not yet producing. This term serves as a guide in our acquisition strategy, enabling us to pinpoint lower-risk investment opportunities for our stakeholders.

Previous wording

In the six months ended June 30, 2026, the E&P operators of our properties, including PhoenixOp, drilled 213 gross and 44.8 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 141 gross and 29.6 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the six months ended June 30, 2025.

Current wording

In the nine months ended September 30, 2026, the E&P operators of our properties, including PhoenixOp, drilled 445 gross and 53.6 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 278 gross and 44.4 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the nine months ended September 30, 2025.

Previous wording

Included in our total drilled wells figures, as of June 30, 2026, PhoenixOp had drilled a total of 147 gross and 128.9 net productive development wells, all of which were drilled in the Williston Basin in North Dakota and Montana. PhoenixOp has also drilled a total of 26 gross and 26 net saltwater disposal wells, and had 56 gross and 35.0 net development wells in progress as of June 30, 2026.

Current wording

Included in our total drilled wells figures, as of September 30, 2026, PhoenixOp had drilled a total of 152 gross and 131.6 net productive development wells, all of which were drilled in the Williston Basin in North Dakota and Montana. PhoenixOp has also drilled a total of 27 gross and 27 net saltwater disposal wells, and had 81 gross and 49.7 net development wells in progress as of September 30, 2026.

Previous wording

As of June 30, 2026, we owned mineral, royalty, and working interests in 8,615 total gross wells and 196.7 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of June 30, 2026:

Current wording

As of September 30, 2026, we owned mineral, royalty, and working interests in 8,843 total gross wells and 208.6 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of September 30, 2026:

Previous wording

As of June 30, 2026, we have 398,263 gross and 55,291 net working interest acres expiring through the end of 2027, with an additional 487,210 gross and 60,229 net working acres expiring in 2028, and 585,628 gross and 86,444 net working interest acres expiring in 2029. The remaining 738,255 gross and 109,359 net working interest acres expire in years 2030 and beyond.

Current wording

As of September 30, 2026, we have 101,964 gross and 51,299 net working interest acres expiring through the end of 2027, with an additional 122,252 gross and 59,655 net working interest acres expiring in 2028, and 168,916 gross and 85,665 net working interest acres expiring in 2029. The remaining 285,725 gross and 142,212 net working interest acres expire in years 2030 and beyond.

Previous wording

Estimates of reserves of oil and natural gas as of December 31, 2025 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2025, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $66.01 per Bbl for oil and $3.387 per MMBtu for natural gas at December 31, 2025. Estimates of reserves of NGL as of December 31, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2025 was $20.90 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Current wording

Estimates of reserves of oil and natural gas as of December 31, 2025 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2025, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $66.01 per Bbl for oil and $3.387 per MMBtu for natural gas at December 31, 2025. Estimates of reserves of NGL as of December 31, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2025 was $20.90 per Bbl. Reserve estimates do not include any possible reserves that may exist, nor do they include any value for undeveloped acreage. Probable reserves are presented separately from proved reserves, are less certain to be recovered than proved reserves, and are not included in PV-10 or the standardized measure. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Previous wording

Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Current wording

Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any possible reserves that may exist, nor do they include any value for undeveloped acreage. Probable reserves are presented separately from proved reserves, are less certain to be recovered than proved reserves, and are not included in PV-10 or the standardized measure. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Previous wording

Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Current wording

Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl.

Previous wording

Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended June 30, 2026 was used, the conversion factor would be approximately 20.01 Mcf per Bbl of oil.

Current wording

Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended September 30, 2026 was used, the conversion factor would be approximately 21.25 Mcf per Bbl of oil.

Previous wording

At June 30, 2026, total estimated proved reserves were approximately 153,231,056 Boe, a 39,617,185 Boe net increase from the estimate of 113,613,871 Boe at December 31, 2025. Proved developed reserves of 65,664,172 Boe represented an increase of approximately 14,043,098 Boe from the estimate of 51,621,074 Boe at December 31, 2025 as a result of proved developed extensions of 31,774,138 Boe and total negative revisions of previous estimates of (17,731,040) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (6,339,512) Boe, (ii) positive price revisions of 8,611 Boe, (iii) negative revisions of (58,089) Boe due to divestitures and trades, (iv) negative revisions of (166) Boe due to schedule adjustments, (v) positive revisions of 20,859,881 Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 3,808,486 Boe, (vii) positive interest adjustments of 3,654,145 Boe, (viii) positive revisions of 2,217,874 Boe due to changes in lifting cost, (ix) negative well performance revisions of (11,333,273) Boe, (x) positive revisions of 1,217,036 Boe due to acquisitions of new properties, and (xi) positive other revisions of 8,105 Boe. Proved undeveloped reserves of 87,566,884 Boe represented an increase of approximately 25,574,087 Boe from the estimate of 61,992,797 Boe at December 31, 2025 as a result of proved undeveloped extensions of 59,102,338 Boe and total negative revisions of previous estimates of (33,528,251) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (729,008) Boe, (ii) negative price revisions of (10,691) Boe, (iii) negative revisions of (11,341,483) Boe due to divestitures and trades, (iv) negative revisions of (432,604) Boe due to schedule adjustments, (v) negative revisions of (20,859,881) Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 1,036,582 Boe, (vii) positive interest adjustments of 4,125,046 Boe, (viii) positive revisions of 947,794 Boe due to changes in lifting cost, (ix) negative well performance revisions of (154,583) Boe, (x) positive revisions of 52,992,012 due to acquisitions of new properties, and (xi) positive other revisions of 903 Boe. During the six months ended June 30, 2026, approximately $460.6 million in capital expenditures went toward the development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells.

Current wording

At September 30, 2026, total estimated proved reserves were approximately 176,560,347 Boe, a 62,946,476 Boe net increase from the estimate of 113,613,871 Boe at December 31, 2025. Proved developed reserves of 70,485,974 Boe represented an increase of approximately 18,864,900 Boe from the estimate of 51,621,074 Boe at December 31, 2025 as a result of transfers of 22,821,348 Boe from proved undeveloped reserves, extensions and acquisitions of new properties of 4,974,800 Boe, and net negative revisions of previous estimates of (8,931,248) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (8,775,582) Boe, (ii) positive price revisions of 181,753 Boe, (iii) negative revisions of (106,917) Boe due to divestitures and trades, (iv) positive revisions of 25,247 Boe due to schedule adjustments, (v) positive shrink and yield revisions of 4,075,017 Boe, (vi) positive interest adjustments of 2,157,836 Boe, (vii) positive revisions of 1,923,375 Boe due to changes in lifting cost, (viii) negative well performance revisions of (8,418,992) Boe, and (ix) positive other revisions of 7,015 Boe. Proved undeveloped reserves of 106,074,373 Boe represented an increase of approximately 44,081,576 Boe from the estimate of 61,992,797 Boe at December 31, 2025 as a result of extensions and acquisitions of new properties of 70,381,209 Boe, transfers of (22,821,348) Boe to proved developed reserves, and net negative revisions of previous estimates of (3,478,285) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (2,520,924) Boe, (ii) positive price revisions of 219,061 Boe, (iii) negative revisions of (11,747,268) Boe due to divestitures and trades, (iv) negative revisions of (298,939) Boe due to schedule adjustments, (v) positive shrink and yield revisions of 1,139,909 Boe, (vi) positive interest adjustments of 8,384,141 Boe, (vii) positive revisions of 866,632 Boe due to changes in lifting cost, (viii) positive well performance revisions of 478,627 Boe, and (ix) positive other revisions of 476 Boe. During the nine months ended September 30, 2026, approximately $834.7 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, facility, and capital workover costs, and the proved portion of property acquisitions.

Previous wording

At December 31, 2023, total estimated proved reserves were approximately 45,516,226 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, partially offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of 89,378 Boe from proved developed to proved undeveloped due to previous misclassifications of reserve; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2023 are scheduled to be converted to proved developed status within five years of initial disclosure.

Current wording

At December 31, 2023, total estimated proved reserves were approximately 45,516,226 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, partially offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserves; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2023 are scheduled to be converted to proved developed status within five years of initial disclosure.

Previous wording

We are subject to arrangements pursuant to which we have committed to deliver barrels of crude oil to a purchaser through December 31, 2030. We will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, we have dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, North Dakota. We have assessed the productivity potential of our leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on our leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement. As of June 30, 2026, we delivered approximately 1.4 million barrels of crude oil and the remaining aggregate commitment under the contract is approximately 0.8 million barrels of crude oil. Based on current production levels from the dedicated acreage, we believe we have sufficient production capacity to satisfy the remaining contractual volume commitments. However, future production levels are subject to operational, commodity price, and reservoir performance risks. In the event of a shortfall, any associated fees would not be expected to materially impair our liquidity position.

Current wording

We are subject to arrangements pursuant to which we have committed to deliver barrels of crude oil to a purchaser through December 31, 2030. We will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, we have dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, North Dakota. We have assessed the productivity potential of our leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on our leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement. As of September 30, 2026, we delivered approximately 1.5 million barrels of crude oil and the remaining aggregate commitment under the contract is approximately 0.7 million barrels of crude oil. Based on current production levels from the dedicated acreage, we believe we have sufficient production capacity to satisfy the remaining contractual volume commitments. However, future production levels are subject to operational, commodity price, and reservoir performance risks. In the event of a shortfall, any associated fees would not be expected to materially impair our liquidity position.

Previous wording

In May 2026, we entered into a fifteen-year gas gathering and processing contract with a third-party provider pursuant to which we have committed to deliver substantially all natural gas production from certain dedicated acreage in the Divide, Williams, and Dunn Counties in North Dakota, for gathering and processing services estimated to commence in March 2027. We are subject to a five-year minimum volume commitment of 20.0 million Mcf beginning on the commencement date, with an annual minimum requirement of 4.0 million Mcf, and may be subject to a shortfall fee. Deliveries in excess of annual commitments generate volume credits that may be applied against future annual commitments. Under this agreement, we pay gathering, compression, and other service fees based primarily on production volumes delivered. We have also agreed to fund certain AIC costs associated with the construction of gathering infrastructure totaling $10.0 million, of which $4.0 million was paid in May 2026 and $3.0 million is to be paid in November 2026. The final installment of $3.0 million is payable upon the achievement of certain specified milestones by the provider.

Current wording

In May 2026, we entered into a fifteen-year gas gathering and processing contract with a third-party provider pursuant to which we have committed to deliver substantially all natural gas production from certain dedicated acreage in the Divide, Williams, and Dunn Counties in North Dakota, for gathering and processing services. We are subject to a five-year minimum volume commitment of 20.0 million Mcf beginning in March 2027, with an annual minimum requirement of 4.0 million Mcf, and may be subject to a shortfall fee. Deliveries in excess of annual commitments generate volume credits that may be applied against future annual commitments. As of September 30, 2026, we delivered approximately 0.2 million Mcf, which will be credited toward the first year’s minimum volume requirement. Under this agreement, we pay gathering, compression, and other service fees based primarily on production volumes delivered. We have also agreed to fund certain AIC costs associated with the construction of gathering infrastructure totaling $10.0 million, of which $4.0 million was paid in May 2026 and $3.0 million is to be paid in November 2026. The final installment of $3.0 million is payable upon the achievement of certain specified milestones by the provider.

Previous wording

Depletion expense was $133.8 million and $67.8 million for the six months ended June 30, 2026 and 2025, respectively. On a per unit basis, depletion expense was $19.07 per Boe and $17.27 per Boe for the six months ended June 30, 2026 and 2025, respectively. In addition, there was a decrease in our depletion rate for the six months ended June 30, 2026 compared to 2025 primarily due to increased proved reserves relative to the change in aggregated proved leasehold and development costs associated with those proved reserves. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method. We expect overall depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.

Current wording

Depletion expense was $222.1 million and $113.3 million for the nine months ended September 30, 2026 and 2025, respectively. On a per unit basis, depletion expense was $19.74 per Boe and $17.49 per Boe for the nine months ended September 30, 2026 and 2025, respectively. The increase in depletion expense was primarily due to higher production volumes and a higher depletion rate, which resulted from growth in the depletable cost base outpacing growth in proved reserves. Under the successful efforts method, development costs are depleted over proved developed reserves, while leasehold costs are depleted over total proved reserves, resulting in a higher depletion rate for development costs. We expect depletion expense to continue to increase in subsequent periods as our net production of oil, natural gas, and NGL increases.

Previous wording

PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our oil and natural gas reserves.

Current wording

PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purports to represent the fair value of our oil and natural gas reserves.