Phoenix Energy One, LLC
For the period ended Jun 30, 2026. Filed Aug 10, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2026 · Filed Aug 10, 2026
PHXE-P$25.32-0.7%Stored close · as of Nov 6, 2026
What changed in Risk Factors?
Read the current filingPrevious report: 10-Q
Period ended 2026-03-31; filed 2026-05-13.
0001193125-26-221647
Item 1A. Risk FactorsUnregistered Sales of Equity Securities and Use of ProceedsDefaults Upon Senior SecuritiesMine Safety DisclosuresOther InformationCurrent report: 10-Q
Period ended 2026-06-30; filed 2026-08-10.
0001193125-26-342420
Item 1A. Risk FactorsUnregistered Sales of Equity Securities and Use of ProceedsDefaults Upon Senior SecuritiesMine Safety DisclosuresOther InformationThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 55 previous paragraphs and 59 current paragraphs.
41 unchanged; 13 reworded; 5 added; 1 removed; 0 previous and 0 current paragraphs rearranged.
Tables are not compared: 9 previous and 9 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (5)
Current report
The Fortress Credit Agreement contains various customary covenants, including financial covenants that require us to maintain ratios around our maximum total secured leverage, minimum asset coverage, current assets to current liabilities, and working capital as of the last day of each calendar month or fiscal quarter, as the case may be. On August 10, 2026, subsequent to the balance sheet date, the Company obtained a waiver of noncompliance with (i) its current ratio covenant as of the last day of each calendar month ending during the period from April 30, 2026 through and including July 31, 2026, which resulted primarily from the timing of accelerated well completion expenditures undertaken to capitalize on higher commodity prices, and (ii) its covenant to enter into and maintain certain swap agreements as of June 30, 2026.
Current report
Estimates of reserves of oil and natural gas as of June 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 June 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 $72.93 per Bbl for oil and $3.644 per MMBtu for natural gas at June 30, 2026. Estimates of reserves of NGL as of June 30, 2026 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at June 30, 2026 was $24.61 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 report
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.
Removed paragraphs (1)
Previous report
Estimates of reserves of oil and natural gas as of March 31, 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 March 31, 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 $63.80 per Bbl for oil and $3.720 per MMBtu for natural gas at March 31, 2026. Estimates of reserves of NGL as of March 31, 2026 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at March 31, 2026 was $21.15 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.
Reworded paragraphs (13)
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 $56.7 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.4 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.
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 $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.
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 March 31, 2026, we owned mineral, royalty, and working interests in 8,192 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 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.
Previous wording
As of March 31, 2026, we had 245 wells that fall under our “wells in progress” (“WIP”) category, and we had 86 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 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.
Previous wording
In the three months ended March 31, 2026, the E&P operators of our properties, including PhoenixOp, drilled 33 gross and 13.7 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 26 gross and 4.2 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, 2025.
Current 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.
Previous wording
Included in our total drilled wells figures, as of March 31, 2026, PhoenixOp had drilled a total of 113 gross and 101.2 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 22 gross and 22 net saltwater disposal wells, and had 93 gross and 74.1 net development wells in progress as of March 31, 2026.
Current 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.
Previous wording
As of March 31, 2026, we owned mineral, royalty, and working interests in 8,192 total gross wells and 182.9 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of March 31, 2026:
Current 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:
Previous wording
As of March 31, 2026, we have 459,413 gross and 66,096 net working interest acres expiring through the end of 2027, with an additional 547,882 gross and 69,696 net working acres expiring in 2028, and 555,754 gross and 83,420 net working interest acres expiring in 2029. The remaining 458,456 gross and 79,323 net working interest acres expire in years 2030 and beyond.
Current 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.
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 March 31, 2026 was used, the conversion factor would be approximately 17.15 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 June 30, 2026 was used, the conversion factor would be approximately 20.01 Mcf per Bbl of oil.
Previous wording
At March 31, 2026, total estimated proved reserves were approximately 144,753,066 Boe, a 31,139,195 Boe net increase from the estimate of 113,613,871 at December 31, 2025. Proved developed reserves of 65,207,650 Boe represented an increase of approximately 13,586,576 Boe from the estimate of 51,621,074 Boe at December 31, 2025 as a result of proved developed extensions of 23,706,620 Boe and total negative revisions of previous estimates of (10,120,044) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (3,421,490) Boe, (ii) negative price revisions of (124,286) Boe, (iii) negative revisions of (26,125) Boe due to divestitures and trades, (iv) negative revisions of (6) Boe due to schedule adjustments, (v) positive revisions of 14,720,684 Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 4,436,385 Boe, (vii) positive interest adjustments of 2,450,538 Boe, (viii) positive revisions of 2,042,482 Boe due to changes in lifting cost, (ix) negative well performance revisions of (6,548,137) Boe, and (x) positive revisions of 56,531 due to acquisitions of new properties. Proved undeveloped reserves of 79,545,415 Boe represented an increase of approximately 17,552,618 Boe from the estimate of 61,992,797 Boe at December 31, 2025 as a result of proved undeveloped extensions of 34,411,537 Boe and total negative revisions of previous estimates of (16,858,919) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (108,060) Boe, (ii) negative price revisions of (116,724) Boe, (iii) negative revisions of (1,820,353) Boe due to divestitures and trades, (iv) positive revisions of 62,301 Boe due to schedule adjustments, (v) negative revisions of (14,720,684) Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 2,155,135 Boe, (vii) positive interest adjustments of 4,318,801 Boe, (viii) positive revisions of 1,263,287 Boe due to changes in lifting cost, (ix) negative well performance revisions of (93,098) Boe, and (x) positive revisions of 26,612,013 Boe due to acquisitions of new properties. During the three months ended March 31, 2026, approximately $186.1 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 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.
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. We delivered 0.2 million barrels of crude oil during the three months ended March 31, 2026, and the remaining aggregate commitment under the contract as of March 31, 2026 is approximately 1.0 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 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.
Previous wording
“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.
Current wording
“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.
Previous wording
Operating costs per Boe increased in 2025 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.
Current wording
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.
Previous wording
Depletion expense was $60.0 million and $31.3 million for the three months ended March 31, 2026 and 2025, respectively. On a per unit basis, depletion expense was $17.56 per Boe and $17.77 per Boe, for the three months ended March 31, 2026 and 2025, respectively. The decrease in our depletion rate for the three months ended March 31, 2026 compared to 2025 was 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 $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.