Phoenix Energy One, LLC

Item 5. Other Information

During the three months ended September 30, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

10-Q Oil and Gas Disclosures

Our Oil and Natural Gas Properties

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 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.

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.

Drilling Results

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.

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.

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 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:

Acreage of Mineral and Working Interests

The following tables set forth information relating to the acreage underlying our mineral and working interests as of September 30, 2026:

Acreage of Mineral Interest

Acreage of Working Interest

Acreage Expirations

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.

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:

(1)

Estimates of reserves of oil and natural gas as of September 30, 2026 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 September 30, 2026, 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 $76.93 per Bbl for oil and $3.620 per MMBtu for natural gas at September 30, 2026. Estimates of reserves of NGL as of September 30, 2026 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at September 30, 2026 was $16.22 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.

(2)

In early 2022, 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, 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.

(4)

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.

(5)

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 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.

(6)

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.

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.

At December 31, 2025, total estimated proved reserves were approximately 113,613,871 Boe, a 49,804,545 Boe net increase from the estimate of 63,809,326 Boe at December 31, 2024. The increase was primarily the result of extensions and discoveries of 71,088,631 Boe, partially offset by revisions of previous estimates of (12,396,675) Boe and production of (9,924,337) Boe during the year. Proved developed reserves of 51,621,074 Boe represented an increase of 26,677,982 Boe from December 31, 2024, primarily due to extensions and discoveries of 8,782,530 Boe, transfers of 19,515,344 Boe from proved undeveloped reserves, purchases of reserves in place of 571,500 Boe, and revisions of previous estimates of 8,008,132 Boe, partially offset by production of (9,924,337) Boe and divestitures and trades of (275,187) Boe. The revisions of previous estimates affecting proved developed reserves comprised of timing adjustments associated with the effective-date roll-forward, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. Proved undeveloped reserves of 61,992,797 Boe represented an increase of 23,126,563 Boe from December 31, 2024, primarily due to extensions and discoveries of 62,306,101 Boe and purchases of reserves in place of 740,613 Boe, partially offset by transfers of (19,515,344) Boe to proved developed reserves and revisions of previous estimates of (20,404,807) Boe. The revisions of previous estimates affecting proved undeveloped reserves primarily reflected timing adjustments associated with the effective-date roll-forward of reserve estimates, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. During the year ended December 31, 2025, approximately $686.8 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.

At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, an 18,293,100 Boe net increase from the previous year end’s estimate of 45,516,226 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, partially 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 38,866,234 Boe increased approximately 4,030,678 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 Boe 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 45,516,226 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.

Delivery Commitments

Crude Oil Commitments

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.

Natural Gas Gathering Commitments

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.

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:

(1)

Natural gas volumes represent volumes produced and sold during the periods presented and are included in Total (Boe) and Average daily production (Boe/d) on that basis. Natural gas volumes produced, but not sold, are excluded.

(2)

“Boe-equivalent” production volumes are presented on a Boe basis by converting natural gas to oil equivalent using a conversion factor of six Mcf of natural gas to one Bbl of oil, which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

(3)

Operating costs per Boe increased in 2025 and 2026 primarily due to (i) the increased proportion of operated production as compared to royalty production, which carries higher direct operating expenses, (ii) inflationary pressures on field services and disposal costs, and (iii) the integration of newly developed wells into our production base. We expect unit costs to moderate over time as operated production scales and fixed field-level costs are absorbed across a larger production base.

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 $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.

PV-10

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 U.S. 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 purports 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: