Phoenix Energy One, LLC

Current report

Item 1A. Risk Factors

Current report

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors set forth in the section of our 2025 Annual Report entitled “Risk Factors.” These factors could materially adversely affect our business, financial condition, liquidity, results of operations and capital position, and could cause our actual results to differ materially from our historical results or the results contemplated by any forward-looking statements contained in this Quarterly Report. There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in our 2025 Annual Report.

Current report

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Current report

(a)Recent Sales of Unregistered Securities: None.

Current report

(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.

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(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers: None.

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Item 3. Defaults Upon Senior Securities.

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Item 4. Mine Safety Disclosures.

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Item 5. Other Information

Current report

During the three months ended March 31, 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.

Current report

10-Q Oil and Gas Disclosures

Current report

Productive Wells

Current report

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 report

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 report

Drilling Results

Current report

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 report

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 report

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.

Current report

Wells

Current report

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 report

Acreage of Mineral and Working Interests

Current report

The following tables set forth information relating to the acreage underlying our mineral and working interests as of March 31, 2026:

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Acreage of Mineral Interest

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Acreage of Working Interest

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Acreage Expirations

Current report

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 report

The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:

Current 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.

Current report

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.

Current report

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

Current report

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

Current report

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

Current report

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 report

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 report

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.

Current report

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.

Current report

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

Current report

Delivery Commitments

Current report

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 report

Select Production and Operating Statistics

Previous report

Risks Related to Our Business and Operations

Previous report

The businesses of direct drilling and extraction of minerals and acquisition of mineral rights are highly competitive. If we are unable to successfully compete within these businesses through our direct drilling operations conducted by PhoenixOp, we may not be able to identify and purchase attractive assets and successfully operate our properties.

Previous report

The key areas in which we face competition include:

Previous report

Our competitors include entities with greater technical, physical, and financial resources than we have. Furthermore, companies and certain private equity firms not previously investing in minerals and their extraction may choose to acquire reserves to establish a firm supply or simply as an investment. If we are unable to successfully compete in operating our wells or acquisition of attractive assets, we may not be able to achieve or maintain profitable operations.

Previous report

The mineral rights investment business involves high-risk activities with many uncertainties.

Previous report

Our and our operating partners’ activities relating to our mineral rights investment business are subject to many risks, including unanticipated problems relating to finding mineral rights assets and additional costs and expenses that may exceed current estimates. There can be no assurance that the expenditures we make in the exploration phase will result in the discovery of economic deposits of minerals, or that any investment we make in initially profitable assets will continue to be productive enough for associated revenues to be commercially viable. In addition, drilling and producing operations on the assets we invest in may be curtailed, delayed, or canceled by the operators of our properties as a result of various factors, including:

Previous report

In addition to causing curtailments, delays, and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources, and equipment, pollution, environmental contamination, loss of wells, regulatory penalties, and third-party claims. The insurance we maintain against various losses and liabilities arising from our operations does not cover all operational risks involved in our investments. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, and results of operations.

Previous report

We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us.

Previous report

We, through the operations of PhoenixOp, face numerous risks relating to our drilling activities, including:

Previous report

Risks we may face while completing our wells include, but are not limited to:

Previous report

Further, many factors may occur that cause us to curtail, delay, or cancel scheduled drilling and completion projects, including, but not limited to:

Previous report

As we expand our direct drilling and extraction activities the impact of these risks on our overall business will only grow more significant. See “—The businesses of direct drilling and extraction of minerals and acquisition of mineral rights are highly competitive. If we are unable to successfully compete within these businesses through our direct drilling operations conducted by PhoenixOp, we may not be able to identify and purchase attractive assets and successfully operate our properties,” “—Our business is sensitive to the price of oil and gas, and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow,” “—Properties we acquire for our direct drilling and extraction operations, currently conducted through PhoenixOp, may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities,” and “—Our development of successful operations relies extensively on our direct operations, through PhoenixOp and various third-party E&P operators, which could have a material adverse effect on our results of operations.”

Previous report

We are not insured against all risks associated with our business. We and PhoenixOp may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, some risks such as those stemming from certain environmental hazards are generally not fully insurable.

Previous report

Losses and liabilities arising from any of the above events could reduce the value of our capital contributions to PhoenixOp, increase our need to provide additional capital to PhoenixOp, and otherwise harm our financial position, which could adversely affect us and our ability to pay our obligations.

Previous report

Our business is sensitive to the price of oil and gas, and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.

Previous report

Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. During the period from January 1, 2021 through September 30, 2025, prices for crude oil reached a high of $123.64 per Bbl and a low of $47.47 per Bbl. Over the same time period, natural gas prices reached a high of $23.86 per MMBtu and a low of $1.21 per MMBtu. A decline in oil and natural gas prices can have an adverse effect on the value of our interests in the land and revenue from our own direct drilling production, which will materially and adversely affect our ability to generate cash flows and, in turn, our ability to make interest and principal payments on the Notes and distribution payments on the Preferred Shares.

Previous report

The prices received for oil and natural gas produced on our land, and the levels of the production, depend on numerous factors beyond our control and include the following:

Previous report

These factors and the volatility of oil and natural gas prices make it extremely difficult to predict future crude oil, natural gas, and NGL price movements or to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Certain actions by OPEC and other oil producing nations in the first half of 2020, combined with the impact of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the United States, contributed to the historic low price for crude oil in April 2020. While the prices for crude oil have generally increased since then, such prices have historically remained volatile, which has adversely affected the prices at which production from our properties is sold, as well as the production activities of operators on our properties, and may continue to do so in the future. This, in turn, has and will materially affect the amount of royalty payments that we receive from our third-party E&P operators and our income from direct drilling operations. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. In particular, our five-year development plan is based on assumed average oil and natural gas prices of $64.39 per barrel and $3.85 per MMBtu, respectively, and our outlook for 2025 is based on average benchmark commodity prices of $71.98 per barrel for crude oil and $3.94 per Mcf for natural gas, which are significantly higher than recent lows of $58.29 per barrel of for crude oil, as of October 16, 2025 and $2.65 per MMBtu for natural gas, as of October 17, 2025. Although prices have recovered since then, there can no be assurance that prices will not experience another significant decrease. This plan and outlook may need to be adjusted in the future as a result of any material sustained decrease in oil and natural gas prices as compared to our assumptions, which could have a material adverse effect on our business, financial condition, results of operations, and prospects. In addition, in response to a sustained decrease in oil and natural gas prices, we may determine to adjust our overall business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. Such actions and circumstances would impact our revenue, operating expenses, and liquidity. For example, we may be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan.

Previous report

Our revenues, operating results, profitability, and future rate of growth depend primarily on the prices of oil and, to a lesser extent, natural gas that we sell. Any substantial decline in the price of crude oil, natural gas, and NGL or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations, and cash flows. Further, a slowdown in the timing of oil or natural gas production, especially if in connection with a decline in prices, may reduce our ability to collect lease payments from leaseholders, which could limit our ability to make interest and principal payments on the Notes and distribution payments on the Preferred Shares. Prices also affect the amount of cash flow available for capital expenditures and our ability to raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.

Previous report

We have a limited operating history and have experienced periods of significant business growth in a short time, making it difficult for you to evaluate our business and prospects. If we are unable to manage our business and growth effectively, our business could be materially and adversely affected.

Previous report

Since our formation in 2019, our business has grown considerably. Our limited operating history and the significant growth in operations and revenue we have experienced since then makes evaluation of our business and prospects difficult. Any growth that we experience in the future will require us to further expand our drilling and extraction activities and our acquisitions. There can be no assurance that growth in our revenue and operations will continue at a similar pace, or that we will be able to manage our growth effectively. Furthermore, the growth of our business places significant demands on our management, including managing increased numbers of personnel, properties, and business relations, such as our E&P operators. If we do not effectively manage the increased obligations brought by the growth of our operations, we may not be able to execute on our business plan, respond to competitive pressures, take advantage of market opportunities, or satisfy delivery requirements, which could have a material adverse effect on our business, financial condition, results of operations, and prospects.

Previous report

In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly acquired assets, such as failing to integrate, or realizing the expected benefits of, such assets. As a result of the foregoing, we may be less successful in achieving consistent results and continue the growth of our business, as compared with companies that have longer operating histories and a more stable size of operations. In addition, we may be less equipped to identify and address risks and hazards in the conduct of our business than those companies that have longer operating histories.

Previous report

The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise.

Previous report

The oil and gas industry is capital-intensive. We make, and will continue to make, substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions, cash generated by operations, borrowings under credit facilities, and issuances of debt securities. Future sources of liquidity may also include other credit facilities, additional capital contributions, asset-backed securitizations, and continued issuances of debt or equity securities. For example, as part of our general financing and operational strategy, we may in the future undertake securitizations of certain assets or interests in assets through special purpose vehicles.

Previous report

In the future, we may need capital in excess of the amounts we retain in our business, borrow under our existing credit facilities, or through issuances of debt or equity securities. There can be no assurance that we can increase the borrowing amount available under our existing credit facilities or continue to raise sufficient funds through our debt or other securities issuances.

Previous report

Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. For example, a significant decline in prices for oil and natural gas, rising interest rates, inflationary pressure, and broader economic turmoil may adversely impact our ability to secure financing in the capital markets on favorable terms. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and financial condition.

Previous report

Most of our third-party E&P operators are also dependent on the availability of external debt, equity financing sources, and operating cash flows to maintain their drilling programs. If those financing sources are not available to such third-party E&P operators on favorable terms or at all, then we expect the development of our properties would be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.

Previous report

Properties we acquire for our direct drilling and extraction operations, currently conducted through PhoenixOp, may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities.

Previous report

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including, but not limited to, environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we acquire may not produce as projected. In connection with these assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. While conducting due diligence, we may not review every well, pipeline, or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from any seller for liabilities arising from or attributable to the period prior to our purchase of the property. As a result, we may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Previous report

We may encounter obstacles to marketing our minerals, which could adversely impact our revenues and profits.

Previous report

The marketability of our production will depend upon numerous factors beyond our control, including the availability and capacity of natural gas gathering systems, pipelines, and other transportation and processing facilities owned by third parties.

Previous report

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells, and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

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The marketing of our production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation. The availability of markets for our production is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market mineral deposits.

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If we have difficulty selling the oil and gas we produce, our profits may decline, and we may not be able to purchase other assets, or expand our operations.

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A limited number of purchasers and operators currently generate a significant portion of our revenue and/or accounts receivable, and we may not have contracts or agreements directly with all such operators.

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A significant portion of our consolidated revenue is generated from product sales for the delivery of commodities that we extract and deliver to purchasers, and we currently deliver to a limited number of purchasers. For example, for the nine months ended September 30, 2025, three purchasers of our commodities made up 54.0% of our consolidated revenue, as compared to one purchaser of our commodities that made up 30.0% of our consolidated revenue for the nine months ended September 30, 2024 and one purchaser of our commodities that made up 21.0% of our consolidated revenue for the year ended December 31, 2024. While we do not believe that the loss of any one purchaser would have a material impact on our revenue, to the extent there is a delay in transferring our commodity sales or entering into purchase contracts with another, new or replacement purchaser, there could be a delay in product sales or an adverse impact on our revenue during the respective period. A large portion of our current mineral rights and lease holdings are serviced by a limited number of third-party E&P operators and, as a result, we generate a significant portion of our revenue and accounts receivable from a limited number of third-party E&P operators. For the nine months ended September 30, 2025, twelve third-party E&P operators made up 16.0% of our consolidated revenue, as compared to six third-party E&P operators that made up 33.0% of our consolidated revenue for the nine months ended September 30, 2024. For the year ended December 31, 2024, one third-party E&P operator made up 21.0% of our consolidated revenue, as compared to one third-party E&P operator that made up 11.0% of our consolidated revenue for the year ended December 31, 2023, and four third-party E&P operators that made up 16.0%, 16.0%, 15.0%, and 14.0% of our consolidated revenue for the year ended December 31, 2022. Similarly, as of September 30, 2025, we had concentrations in accounts receivable of 19.0%, 12.0% and 11.0% with three purchasers of our commodities and 12.0% with one third-party E&P operator, as compared to 17.0%, 15.0%, and 13.0% with three third-party E&P operators as of December 31, 2024, 26.0% and 14.0% with two third-party E&P operators as of December 31, 2023, and 34.0% and 10.0% with two third-party E&P operators as of December 31, 2022. A significant portion of our revenue and accounts receivable are generally derived from our diverse holdings of mineral rights and lease holdings and are generally not generated pursuant to agreements directly between us and the operators of the properties underlying our mineral rights and lease holdings. These interests generate revenue from the sale of crude oil and natural gas, which is paid monthly to us by various third-party oil and gas operators once any extracted crude oil and natural gas is delivered by such operators to purchasers. Those purchasers remit payment for production to the operators of the wells pursuant to sales agreements entered …

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As is typical in the oil and gas industry, the third-party oil and gas operators generally remit payment to the interest owners pursuant to statute or orders from the oil and gas commission of the state in which the particular well (or unit of wells) is located. For example, the majority interest holders of a unit would petition to appoint a particular operator from the oil and gas commission of the state in which the unit is located (e.g., the Wyoming Oil and Gas Commission, North Dakota Industrial Commission, Texas Railroad Commission (the “Texas RRC”), Montana Board of Oil and Gas Conservation, and Utah Division of Oil, Gas and Mining, among others). If the request is granted by the commission, the operator would become the designated operator for the unit and would be required to remit payments to the interest holders of the unit pursuant to permits or pooling orders from such commission. While our revenue and accounts receivable relating to our mineral rights and lease holdings are derived from a significant number of different units that are subject to different leases and pooling orders from various state oil and gas commissions, the incapacity or loss of one of the operators that generate a significant portion of our revenue and accounts receivable could negatively impact our revenue and accounts receivable and could result in a reduction or delay in revenue generated from the related mineral rights and lease holdings while a replacement operator is selected and designated. Further, although typical in the oil and gas industry, as we do not always have contracts or agreements directly with these operators, we do not always determine or control the rights, payments, discounts, or other terms related to leases or the extraction and sale of assets from the properties underlying our mineral rights and lease holdings.

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Our development of successful operations relies extensively on our direct operations, through PhoenixOp and various third-party E&P operators, which could have a material adverse effect on our results of operations.

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A significant portion of our assets consist of mineral and royalty interests. We utilize and will continue to utilize third-party E&P operators to perform the drilling and extraction operations on our assets to extract the natural resources we rely on to generate revenue. The success of our business operations depends on the timing of drilling activities and success of our direct operations and third-party E&P operators. If we or our third-party E&P operators are not successful in the development, exploitation, production, and exploration activities relating to our ownership interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

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With respect to our investments in which we have anon-operated working interest, third-party E&P operators will make decisions in connection with their operations, which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our third-party E&P operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our third-party E&P operators could prevent us from realizing target returns for those locations. The success and timing of development activities by our operators will depend on several factors that are largely outside of our control, including: the capital costs required for drilling activities by our third-party E&P operators, which could be significantly more than anticipated; the ability of our operators to access capital; prevailing mineral prices and other factors generally affecting the industry operating environment; the timing of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of drilling technology; the availability of storage for hydrocarbons; and the rate of production of reserves, if any.