UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
CURRENT REPORT
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Item 2.02 – Results of Operations and Financial Condition
On June 5, 2025, Phoenix Energy One, LLC (the “Company”) announced the following information related to its oil and gas production, reserves and drilling for the three months ended March 31, 2025. Unless otherwise indicated or unless the context requires otherwise, all references in this report to “we,” “us” or “our” refer to the Company.
Productive Wells
Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of March 31, 2025, we owned mineral, royalty, and working interests in 6,956 productive wells, the majority of which are oil wells that also produce natural gas and natural gas liquids (“NGL”).
As of March 31, 2025, we had 113 wells that fall under our “wells in progress” (“WIP”) category and we had 32.3 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: (1) a well that is not actively being drilled but is in the process of being developed; (2) a well currently being drilled and awaiting completion; (3) a drilled well in the completion process; and (4) 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.
Drilling Results
In the three months ended March 31, 2025, the exploration and production (“E&P”) operators of our properties, including Phoenix Operating LLC (“PhoenixOp”), a direct, wholly owned subsidiary of the Company , drilled 26 gross and 4.2 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 105 gross and 7.5 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the three months ended March 31, 2024.
In the year ended December 31, 2024, the E&P operators of our properties, including PhoenixOp, drilled 463 gross and 43.2 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 1,965 and 971 gross productive development wells and 19.2 and 8.7 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the years ended December 31, 2023 and 2022, respectively.
Included in our total drilled wells figures, as of March 31, 2025, PhoenixOp had drilled a total of 3,945 gross and 62.2 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 seven gross and seven net saltwater disposal wells, and had 37 gross and 32.9 net development wells in progress as of March 31, 2025.
As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
Wells
As of March 31, 2025, we owned mineral, royalty, and working interests in 6,956 total gross wells and 82.5 total net wells. The following table sets forth information about the productive wells in which we have a mineral or royalty interest as of March 31, 2025:
| Well Count | ||||||||||||||||
| Oil | Gas | |||||||||||||||
| Basin or Producing Region |
Gross | Net | Gross | Net | ||||||||||||
| Bakken/Williston Basin |
3,942 | 62.2 | 3 | 0.0 | ||||||||||||
| DJ Basin/Rockies/Niobrara |
1,225 | 15.3 | 7 | 0.0 | ||||||||||||
| Permian Basin |
692 | 1.2 | 2 | 0.0 | ||||||||||||
| Other |
548 | 1.5 | 537 | 2.3 | ||||||||||||
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| Total |
6,407 | 80.2 | 549 | 2.3 | ||||||||||||
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Acreage of Mineral and Royalty Interests
The following tables set forth information relating to the acreage underlying our mineral and working interests as of March 31, 2025:
| ● | Acreage of Mineral Interest |
| Net Royalty Acres | ||||||||||||
| Basin |
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
|||||||||
| Bakken/Williston Basin |
17,043 | 70,067 | 87,111 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
5,010 | 10,280 | 15,290 | |||||||||
| Permian Basin |
657 | 356 | 1,013 | |||||||||
| Other |
470 | 435,374 | 435,845 | |||||||||
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| Total Net Royalty Acres |
23,180 | 516,077 | 539,258 | |||||||||
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| Gross Royalty Acres | ||||||||||||
| Basin |
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
|||||||||
| Bakken/Williston Basin |
552,685 | 929,561 | 1,482,247 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
115,814 | 349,033 | 464,847 | |||||||||
| Permian Basin |
94,083 | 24,603 | 118,685 | |||||||||
| Other |
17,579 | 2,216,297 | 2,233,876 | |||||||||
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| Total Gross Royalty Acres |
780,161 | 3,519,494 | 4,299,655 | |||||||||
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| ● | Acreage of Working Interest |
| Net Mineral Acres | ||||||||||||
| Basin |
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
|||||||||
| Bakken/Williston Basin |
23,989 | 202,340 | 226,329 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
3,953 | 31,877 | 35,830 | |||||||||
| Permian Basin |
28 | 36 | 64 | |||||||||
| Other |
349 | 258,350 | 258,699 | |||||||||
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| Total Net Mineral Acres |
28,319 | 492,603 | 520,922 | |||||||||
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| Gross Mineral Acres | ||||||||||||
| Basin |
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
|||||||||
| Bakken/Williston Basin |
252,672 | 786,065 | 1,038,736 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
43,179 | 189,656 | 232,834 | |||||||||
| Permian Basin |
7,680 | 1,280 | 8,960 | |||||||||
| Other |
15,872 | 1,309,568 | 1,325,440 | |||||||||
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| Total Gross Mineral Acres |
319,402 | 2,286,568 | 2,605,971 | |||||||||
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Beginning with the period ended December 31, 2023 and for all subsequent periods, each land holding in which we have a net royalty interest is reviewed and associated with a specific drilling spacing unit. This helps support the accuracy of estimates regarding gross royalty acres. For the period ended December 31, 2022 and for all prior periods, the drilling spacing unit was estimated based on average development within a basin and applied to each land holding in which we had a net royalty interest.
Acreage Expirations
As of March 31, 2025, we have 175,440 gross and 26,193 net working interest acres expiring through the end of 2027, with an additional 243,669 gross and 46,271 net working acres expiring in 2028, and 609,743 gross and 85,202 net working interest acres expiring in 2029. The remaining 454,934 gross and 72,092 net working interest acres expire in years 2030 and beyond.
Oil, Natural Gas, and NGL Reserves
The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:
| As of March 31, 2025(1)(2) |
As of December 31, | |||||||||||||||
| 2024(2)(3) | 2023(2)(4) | 2022(5) | ||||||||||||||
| Estimated proved developed reserves |
||||||||||||||||
| Oil (Bbl) |
21,203,426 | 18,624,758 | 7,124,194 | 3,691,722 | ||||||||||||
| Natural gas (Mcf) |
24,553,454 | 20,819,874 | 12,250,285 | 7,624,212 | ||||||||||||
| Natural gas liquids (Bbl) |
3,690,384 | 2,848,355 | 1,514,761 | — | ||||||||||||
| Total (Boe)(6:1)(6) |
28,986,053 | 24,943,093 | 10,680,669 | 4,962,424 | ||||||||||||
| Estimated proved undeveloped reserves |
||||||||||||||||
| Oil (Bbl) |
31,671,299 | 31,197,795 | 24,925,841 | — | ||||||||||||
| Natural gas (Mcf) |
15,155,549 | 17,491,089 | 19,565,808 | — | ||||||||||||
| Natural gas liquids (Bbl) |
4,662,130 | 4,753,257 | 6,648,747 | — | ||||||||||||
| Total (Boe)(6:1)(6) |
38,859,353 | 38,866,233 | 34,835,556 | — | ||||||||||||
| Estimated proved reserves |
||||||||||||||||
| Oil (Bbl) |
52,874,725 | 49,822,554 | 32,050,035 | 3,691,722 | ||||||||||||
| Natural gas (Mcf) |
39,709,003 | 38,310,963 | 31,816,093 | 7,624,212 | ||||||||||||
| Natural gas liquids (Bbl) |
8,352,514 | 7,601,611 | 8,163,508 | — | ||||||||||||
| Total (Boe)(6:1)(6) |
67,845,406 | 63,809,326 | 45,516,225 | 4,962,424 | ||||||||||||
| Percent proved developed |
43 | % | 39 | % | 23 | % | 100 | % | ||||||||
| Estimated probable undeveloped reserves |
||||||||||||||||
| Oil (Bbl) |
111,100,322 | 107,769,309 | 74,877,268 | — | ||||||||||||
| Natural gas (Mcf) |
134,480,280 | 134,083,603 | 88,184,111 | — | ||||||||||||
| Natural gas liquids (Bbl) |
— | — | — | — | ||||||||||||
| Total (Boe)(6:1)(6) |
133,513,702 | 130,116,577 | 89,574,620 | — |
| (1) | Estimates of reserves of oil and natural gas as of March 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 March 31, 2025, in accordance with U.S. Securities and Exchange Commission (“SEC”) guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $75.33 per one stock tank barrel, of 42 U.S. gallons liquid volume, (“Bbl”) for oil and $2.443 per one million British thermal units (“MMBtu”) for natural gas at March 31, 2025. Estimates of reserves of NGL as of March 31, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at March 31, 2025 was $27.95 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. |
| (2) | In early 2023, PhoenixOp was established with the intention that certain leaseholds held by us would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company on June 20, 2023. This allowed for previously unbooked reserves as of December 31, 2022 to be estimated and booked as of December 31, 2023 as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth in Rule 4-10(a)(31) of Regulation S-X. |
| (3) | 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 last 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. |
| (4) | 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 last 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 $27.50 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. |
| (5) | Estimates of reserves of oil and natural gas as of December 31, 2022 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 last 12 months ended December 31, 2022, 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 $94.14 per Bbl for oil and $6.357 per MMBtu for natural gas at December 31, 2022. We had no NGL reserves as December 31, 2022 and, as such, no NGL price was calculated as of December 31, 2022. 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. |
| (6) | Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six one thousand cubic feet (“Mcf”) per barrel of “oil equivalent.” (“Boe”) 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 December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil. |
At March 31, 2025, total estimated proved reserves were approximately 67,845,406 Boe, a 4,036,080 Boe net increase from the estimate of 63,809,326 at December 31, 2024. Proved developed reserves of 28,986,052 Boe represented an increase of approximately 5,802,281 Boe from December 31, 2024 as a result of proved developed reserves sales and acquisitions of 599,398 Boe, extensions of 366,232 Boe, and total positive revisions of previous estimates of 4,836,651 Boe, offset by production of 1,759,320 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (10,671) Boe, (ii) positive revisions of 4,812,993 Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) negative well performance revisions of (94,482) Boe, (iv) write downs of (77,456) Boe, and (v) positive interest changes of 206,267 Boe. Proved undeveloped reserves of 38,859,353 Boe represented a decrease of approximately (6,880) Boe from December 31, 2024 as a result of proved undeveloped extensions of 3,222,627 Boe and total negative revisions of previous estimates of (3,229,507)
Boe, which comprised (i) negative price revisions (17,599) Boe, (ii) negative revisions of (4,812,993) Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) positive well performance revisions of 1,462,943 Boe, and (iv) positive revisions of 145,022 Boe due to asset development timing. During the three months ended March 31, 2025, approximately $101.2 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells.
At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, a 18,293,101 Boe net increase from the previous year end’s estimate of 45,516,225 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,233 Boe increased approximately 4,030,677 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe; (ii) negative transfer of (14,871,911) Boe from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year ended December 31, 2024, approximately $87.4 million in capital expenditures were related to the conversion of proved undeveloped reserves to proved developed reserves. During the year ended December 31, 2024, approximately $450.0 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. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.
At December 31, 2023, total estimated proved reserves were approximately 45,516,225 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, 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.
At December 31, 2022, total estimated proved reserves were approximately 4,962,424 Boe, a 2,195,112 Boe net increase from the previous year end’s estimate of 2,767,312 Boe. Proved developed reserves of 4,962,424 Boe increased approximately 2,195,112 Boe from December 31, 2021 as a result of proved developed reserves acquisitions of 1,554,122 Boe, extensions of 75,272 Boe, and total positive revisions of previous estimates of 1,265,552 Boe, offset by production from proved developed reserves of 699,834 Boe. The total positive revisions of previous estimates comprised (i) positive price revisions of 524,667 Boe and (ii) positive well performance revisions of 740,885 Boe. During the year ended December 31, 2022, approximately $117.1 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2021, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2022 were related to the conversion of proved undeveloped reserves to proved developed reserves.
Delivery Commitments
As of March 31, 2025, PhoenixOp is subject to arrangements pursuant to which it has committed to provide a total of 2.2 million barrels of crude oil, with the highest yearly minimum of 958,000 barrels of crude oil, from June 1, 2025 to December 31, 2030. PhoenixOp will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, PhoenixOp has dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, Williams County, and Divide County, North Dakota. PhoenixOp has
assessed the productivity potential of its leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on its leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement.
Select Production and Operating Statistics
The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:
| For the Months Ended March 31, | For the Years Ended December 31, | |||||||||||||||||||
| 2025 | 2024 | 2024 | 2023 | 2022 | ||||||||||||||||
| Production Data: |
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| Bakken |
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| Oil (Bbl) |
1,386,145 | 460,994 | 3,022,810 | 943,930 | 360,604 | |||||||||||||||
| Natural gas (Mcf) |
331,296 | 310,389 | 1,301,782 | 1,123,859 | 522,523 | |||||||||||||||
| Natural gas liquids (Bbl) |
54,214 | 53,464 | 270,219 | 88,762 | — | |||||||||||||||
| Total (Boe)(6:1)(1) |
1,495,575 | 566,190 | 3,509,992 | 1,220,003 | 447,691 | |||||||||||||||
| Average daily production (Boe/d)(6:1) |
16,618 | 6,222 | 9,590 | 3,342 | 1,227 | |||||||||||||||
| All Properties |
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| Oil (Bbl) |
1,552,609 | 578,411 | 3,830,461 | 1,446,928 | 523,416 | |||||||||||||||
| Natural gas (Mcf) |
712,492 | 556,282 | 2,979,341 | 2,152,939 | 1,058,506 | |||||||||||||||
| Natural gas liquids (Bbl) |
87,962 | 80,367 | 415,363 | 201,454 | — | |||||||||||||||
| Total (Boe)(6:1)(1) |
1,759,320 | 751,492 | 4,742,381 | 2,007,205 | 699,834 | |||||||||||||||
| Average daily production (Boe/d)(6:1) |
19,548 | 8,258 | 12,993 | 5,499 | 1,917 | |||||||||||||||
| Average Realized Prices: |
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| Bakken |
||||||||||||||||||||
| Oil (Bbl) |
$ | 72.17 | $ | 66.06 | $ | 71.77 | $ | 71.43 | $ | 80.67 | ||||||||||
| Natural gas (Mcf) |
$ | 3.53 | $ | 2.84 | $ | 2.12 | $ | 3.47 | $ | 3.77 | ||||||||||
| Natural gas liquids (Bbl) |
$ | 26.83 | $ | 25.31 | $ | 23.53 | $ | 26.70 | $ | — | ||||||||||
| All Properties |
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| Oil (Bbl) |
$ | 70.50 | $ | 64.51 | $ | 68.49 | $ | 73.10 | $ | 91.01 | ||||||||||
| Natural gas (Mcf) |
$ | 3.13 | $ | 2.48 | $ | 1.86 | $ | 3.15 | $ | 6.66 | ||||||||||
| Natural gas liquids (Bbl) |
$ | 27.95 | $ | 24.48 | $ | 25.22 | $ | 27.50 | $ | — | ||||||||||
| Average Unit Cost per Boe (6:1): |
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| All Properties |
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| Operating costs, production and ad valorem taxes |
$ | 18.01 | $ | 13.69 | $ | 16.11 | $ | 16.18 | $ | 19.89 | ||||||||||
| Operating costs excluding taxes |
$ | 12.21 | $ | 7.95 | $ | 10.75 | $ | 10.86 | $ | 12.58 | ||||||||||
| Percentage of revenue |
27.1 | % | 20.6 | % | 26.4 | % | 16.7 | % | 21.9 | % | ||||||||||
| (1) | “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. |
Depletion of Oil and Natural Gas Properties
We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs, as well as the anticipated proceeds from salvaging equipment.
Depletion expense was $31.3 million and $13.3 million for the three months ended March 31, 2025 and 2024, respectively, and $86.0 million, $34.2 million, and $12.1 million for the years ended December 31, 2024, 2023, and 2022, respectively. On a per unit basis, depletion expense was $17.77 per Boe and $17.63 per Boe for the three months ended March 31, 2025 and 2024, respectively, and $18.13 per Boe, $17.06 per Boe, and $17.34 per Boe for the years ended December 31, 2024, 2023, and 2022, respectively. The increase in our depletion rate for the three months ended March 31, 2025 compared to 2024 was primarily due to the incurrence of increased development capital expenditures primarily related to developing operated wells under our operating entity, PhoenixOp. The decrease in our depletion rate for the year ended December 31, 2023 compared to 2022 was primarily due to increased proved reserves relative to the change in aggregated proved leasehold and development costs associated with those proved reserves, whereas the increase in our depletion rate for the year ended December 31, 2024 compared to 2023 was primarily due to the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. The depletion rate for 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 depletion expense to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.
PV-10
| For the Months Ended March 31, | For the Years Ended December 31, | |||||||||||||||||||
| 2025 | 2024 | 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| PV-10 (estimated proved developed reserves)(1) |
$ | 751,363 | $ | 403,685 | $ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||||||
| PV-10 (estimated proved undeveloped reserves)(1) |
472,937 | 197,585 | 424,595 | 257,472 | — | |||||||||||||||
| PV-10 (estimated total proved reserves)(1) |
1,224,300 | 601,270 | 1,068,692 | 547,281 | 189,885 | |||||||||||||||
| (1) | We calculate PV-10 as the discounted future net cash flows attributable to our proved oil and natural gas reserves before income taxes, discounted at 10% annually. PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable generally accepted accounting principles in the United States (“GAAP”) financial measure, because it is calculated on a pre-tax basis. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, and is useful for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. |
Because the Company is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows. Notwithstanding the foregoing, we believe that the presentation of PV-10 is useful to investors because it is a commonly utilized measure in our industry for assessing the value of reserves.
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.
The following table includes a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:
| For the Months Ended March 31, | For the Years Ended December 31, | |||||||||||||||||||
| 2025 | 2024 | 2024 | 2023 | 2022 | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Estimated proved developed reserves: |
||||||||||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 751,363 | $ | 403,685 | $ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||||||
| Discounted future income taxes |
— | — | — | — | — | |||||||||||||||
| PV-10 |
$ | 751,363 | $ | 403,685 | $ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||||||
| Estimated proved undeveloped reserves: |
||||||||||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 472,937 | $ | 197,585 | $ | 424,595 | $ | 257,472 | $ | — | ||||||||||
| Discounted future income taxes |
— | — | — | — | — | |||||||||||||||
| PV-10 |
$ | 472,937 | $ | 197,585 | $ | 424,595 | $ | 257,472 | $ | — | ||||||||||
| Estimated total proved reserves: |
||||||||||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 1,224,300 | $ | 601,270 | $ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||||||
| Discounted future income taxes |
— | — | — | — | — | |||||||||||||||
| PV-10 |
$ | 1,224,300 | $ | 601,270 | $ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||||||
The information in this Item 2.02, shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Dated: June 5, 2025
| PHOENIX ENERGY ONE, LLC | ||
| By: | /s/ Curtis Allen | |
| Curtis Allen | ||
| Chief Financial Officer | ||