Phoenix Energy One, LLC

During the three months ended September 30, 2025,

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 Disclosure

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, 2025, we owned mineral, royalty, and working interests in 7,335 productive wells, the majority of which are oil wells that also produce natural gas and NGLs.

As of September 30, 2025, we had 180 wells that fall under our “wells in progress” (“WIP”) category, and we had 45.0 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 nine months ended September 30, 2025, the E&P operators of our properties, including PhoenixOp, a direct, wholly owned subsidiary of the Company, drilled 278 gross and 44.4 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 327 gross and 16.7 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, 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 September 30, 2025, PhoenixOp had drilled a total of 78 gross and 69.7 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 14 gross and 14 net saltwater disposal wells, and had 42 gross and 37.2 net development wells in progress as of September 30, 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 September 30, 2025, we owned mineral, royalty, and working interests in 7,335 total gross wells and 126.3 total net wells. The following table sets forth information about the productive wells in which we have a mineral or royalty interest as of September 30, 2025:

Acreage of Mineral and Royalty Interests

The following tables set forth information relating to the acreage underlying our mineral and working interests as of September 30, 2025:

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 September 30, 2025, we have 493,035 gross and 70,837 net working interest acres expiring through the end of 2027, with an additional 478,909 gross and 57,296 net working acres expiring in 2028, and 518,618 gross and 79,300 net working interest acres expiring in 2029. The remaining 320,388 gross and 53,482 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:

At September 30, 2025, total estimated proved reserves were approximately 95,198,985 Boe, a 31,389,659 Boe net increase from the estimate of 63,809,326 at December 31, 2024. Proved developed reserves of 42,050,559 Boe represented an increase of approximately 17,107,466 Boe from December 31, 2024 as a result of proved developed reserves sales and acquisitions of 36,232 Boe, extensions of 1,064,141 Boe, and total positive revisions of previous estimates of 19,062,441 Boe, offset by production of 2,550,211 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (259,733) Boe, (ii) positive revisions of 15,283,658 Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) positive well performance revisions of 550,635 Boe, (iv) write downs of (233,051) Boe, (v) positive interest changes of 3,721,458 Boe and (vi) negative revisions of (526) Boe due to changes in lifting cost. Proved undeveloped reserves of 53,148,426 Boe represented an increase of approximately 14,282,193 Boe from December 31, 2024 as a result of proved undeveloped extensions of 32,605,166 Boe and total negative revisions of previous estimates of (11,794,171) Boe, which comprised (i) negative price revisions (602,036) Boe, (ii) negative revisions of (15,283,658) Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) write downs of (6,437,228) Boe, (iv) positive well performance revisions of 2,422,863 Boe, (v) positive revisions of 119,791 Boe due to asset development timing, (vi) positive interest revisions of 7,995,683 Boe and (vii) negative revisions of (9,586) due to lifting cost changes. During the nine months ended September 30, 2025, approximately $484.6 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 14,262,424 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 40,553,801 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 5,718,244 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 34,835,557 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 September 30, 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, 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:

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

method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the

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 $113.3 million and $52.7 million for the nine months ended September 30, 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 $14.01 per Boe and $15.90 per Boe for the nine months ended September 30, 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 decrease in our depletion rate for the nine months ended September 30, 2025 compared to 2024 was primarily due to reduced realized production volumes within the mineral and

non-operating

segment and the significant growth in proved reserves due to drilling activity by 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

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: