Phoenix Energy (NYSE American: PHXE.P) posts rapid 2025 growth and higher reserves
Rhea-AI Filing Summary
Phoenix Energy One, LLC reports rapid expansion in its 2025 annual filing. Revenue grew to $687.2 million from $281.2 million in 2024 and $118.1 million in 2023, with net income of $66.1 million versus prior losses and EBITDA rising to $403.6 million.
The company has shifted from primarily royalty acquisitions to a three-pronged model that now emphasizes direct drilling through PhoenixOp, alongside royalty and non‑operated working interest acquisitions. Production climbed to 9.9 million Boe in 2025, and proved reserves increased to 113.6 million Boe, with additional probable reserves of 228.0 million Boe.
Growth is funded by significant leverage. As of December 31, 2025, total assets were $1,806.8 million and total liabilities $1,728.6 million, including $1,529.9 million of indebtedness. Management estimates $1,064.1 million and $2,167.3 million of capital will be required to develop proved and probable undeveloped reserves and plans to raise about $669.8 million of additional capital through the end of 2028.
Positive
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Insights
Phoenix Energy shows strong volume and reserve growth but carries heavy leverage and large forward capex needs.
Phoenix Energy has transformed from a small royalty aggregator into an integrated upstream platform. Revenue rose to $687.2 million in 2025, EBITDA to $403.6 million, and production to 9.9 million Boe as direct drilling scaled, especially in the Williston Basin.
Reserves growth is substantial, with proved reserves reaching 113.6 million Boe and probable undeveloped reserves 228.0 million Boe at December 31 2025. PV‑10 of total proved reserves increased to $1,781.4 million, illustrating a much larger underlying asset base compared with prior years.
The balance sheet is highly geared: total liabilities of $1,728.6 million include $1,529.9 million of indebtedness. Management projects $1,064.1 million and $2,167.3 million of capital to develop proved and probable undeveloped reserves, and expects to raise about $669.8 million through 2028. Actual outcomes will depend on commodity prices, drilling performance, and continuing access to instruments such as the Adamantium facility, August 2023 506(c) Bonds, and Registered Notes.
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO |
Commission File Number:
(Exact name of registrant as specified in its charter)
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Registrant’s telephone number, including area code:
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No
As of March 16, 2026, there were
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DOCUMENTS INCORPORATED BY REFERENCE
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Table of Contents
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PART I |
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Item 1. |
Business |
7 |
Item 1A. |
Risk Factors |
33 |
Item 1B. |
Unresolved Staff Comments |
72 |
Item 1C. |
Cybersecurity |
72 |
Item 2. |
Properties |
74 |
Item 3. |
Legal Proceedings |
74 |
Item 4. |
Mine Safety Disclosures |
74 |
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PART II |
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Item 5. |
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
75 |
Item 6. |
[Reserved] |
75 |
Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
76 |
Item 7A. |
Quantitative and Qualitative Disclosures About Market Risk |
108 |
Item 8. |
Financial Statements and Supplementary Data |
111 |
Item 9. |
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
146 |
Item 9A. |
Controls and Procedures |
146 |
Item 9B. |
Other Information |
147 |
Item 9C. |
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
147 |
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PART III |
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Item 10. |
Directors, Executive Officers and Corporate Governance |
148 |
Item 11. |
Executive Compensation |
152 |
Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
160 |
Item 13. |
Certain Relationships and Related Transactions, and Director Independence |
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Item 14. |
Principal Accounting Fees and Services |
164 |
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PART IV |
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Item 15. |
Exhibits and Financial Statement Schedules |
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Item 16. |
Form 10-K Summary |
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Certain Defined Terms
As used in this Annual Report on Form 10-K (this “Annual Report”), unless otherwise noted or the context otherwise requires, references to:
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For ease of reference, we have repeated definitions for certain of these terms in other portions of the body of this Annual Report. All such definitions conform to the definitions set forth above.
Certain monetary amounts, percentages, and other figures included in this Annual Report have been subject to rounding adjustments. Percentage amounts included in this Annual Report have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this Annual Report may vary from those obtained by performing the same calculations using the figures on our consolidated financial statements included elsewhere in this Annual Report. Certain other amounts that appear in this Annual Report may not sum due to rounding.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which are statements regarding all matters that are not historical facts. They appear in a number of places throughout this Annual Report and include statements regarding our current views, hopes, intentions, beliefs, or expectations concerning, among other things, our results of operations, financial condition, liquidity, prospects, growth, strategies, and position in the markets and the industries in which we operate. These forward-looking statements are generally identifiable by forward-looking terminology such as “guidance,” “expect,” “believe,” “anticipate,” “outlook,” “could,” “target,” “project,” “intend,” “plan,” “seek,” “estimate,” “should,” “will,” “would,” “approximately,” “predict,” “potential,” “may,” “continue,” and “assume,” as well as the negative version of such words, variations of such words, and similar expressions referring to the future.
Forward-looking statements are based on our beliefs, assumptions, and expectations, taking into account currently known market conditions and other factors. Our ability to predict results or the actual effect of future events, actions, plans, or strategies is inherently uncertain and involves certain risks and uncertainties, many of which are beyond our control. Our actual results and performance could differ materially from those set forth or anticipated in our forward-looking statements. Factors that could cause our actual results to differ materially from the expectations we describe in our forward-looking statements include, but are not limited to, the factors listed below and in the section entitled “Risk Factors” elsewhere in this Annual Report. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. You are cautioned that the forward-looking statements contained in this Annual Report are not guarantees of future performance, and we cannot assure you that such statements will be realized or that the forward-looking events and circumstances will occur. All forward-looking statements in this Annual Report are made only as of the date of this Annual Report, based on information available to us as of the date of this Annual Report, and we caution you not to place undue reliance on forward-looking statements in light of the risks and uncertainties associated with them.
The matters summarized below and elsewhere in this Annual Report could cause our actual results and performance to differ materially from those set forth or anticipated in forward-looking statements:
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Except as required by law, we are under no duty to, and we do not intend to, update or review any of our forward-looking statements after the date of this Annual Report, whether as a result of new information, future events or developments, or otherwise.
Investors and others should note that we announce financial and other material information using our website (https://phoenixenergy.com/), SEC filings, press releases, public conference calls, and webcasts. We use these channels of distribution to communicate with our investors and members of the public about the Company, our products and services, and other items of interest. Information contained on our website is not part of this Annual Report or our other filings with the SEC.
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PART I
Item 1. Business
Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets for the purpose of exploration, development, production, and sale of crude oil, natural gas, natural gas liquids, and other byproducts through PhoenixOp, Firebird Services, and Firebird Marketing.
Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver-Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uinta, and Denver-Julesburg Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. Since 2020, we experienced significant growth in our business and operations. For example, in 2020, the E&P operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the five years since then, the E&P operators of our properties have operated an additional 7,043 gross and 140.4 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 508 gross and 62.9 net productive development wells were drilled in 2025 alone. As of December 31, 2025, we had 4,478,932 and 562,318 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 9.9 million Boe for the year ended December 31, 2025. In the same period, our number of employees grew from 21 at December 31, 2020 to 206 at December 31, 2025. Additionally, beginning in mid-2023 we commenced direct drilling operations and we spudded our first wells in the third quarter of 2023; our first owned well commenced hydrocarbon production in January 2024 and, as of December 31, 2025, we have drilled a total of 116.0 gross and 105.7 net producing development and injection wells. We expect these direct drilling operations to be a core component of our business strategy going forward.
Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cash flows and primarily target assets that have a potential payback within the short to medium-term and long-term cash flows.
As of December 31, 2025, we have completed 5,495 acquisitions from landowners and other mineral interest owners since 2019 and currently retain approximately 562,318 NRAs in mineral holdings and 626,597 of NMAs in leasehold assets. Over that same period, in addition to completing numerous small transactions, we completed more than 80 transactions larger than 1,000 NMAs that account for approximately 75% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2025, have sold 3,152 NMAs since 2019.
Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through PhoenixOp.
For the years ended December 31, 2025, 2024, and 2023, we had revenue of $687.2 million, $281.2 million, and $118.1 million, respectively, net income (loss) of $66.1 million, $(24.8) million, and $(16.2) million, respectively, and EBITDA of $403.6 million, $150.7 million, and $65.9 million, respectively. As of December 31, 2025 and 2024,
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we had total assets of $1,806.8 million and $1,029.1 million, respectively, total liabilities of $1,728.6 million and $1,063.1 million, respectively (inclusive of total indebtedness of $1,529.9 million and $987.9 million, respectively), and retained earnings (accumulated deficit) of $29.7 million and $(34.5) million, respectively. Through 2025, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt and cash distributions on our preferred equity in 2025. Furthermore, as of December 31, 2025, we estimate that we will need to make approximately $1,064.1 million and $2,167.3 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $669.8 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt arrangements and cash distributions on our preferred equity for the foreseeable future, our current development plan contemplates capital expenditures in excess of operating cash flow in certain periods. Accordingly, we intend to fund a portion of our growth capital through a combination of operating cash flow, available borrowing capacity, and capital markets transactions, consistent with our historical practice. We regularly evaluate our capital structure and liquidity profile to maintain appropriate financial flexibility while executing our development plan. We may from time to time refinance, extend, or restructure portions of our indebtedness through capital markets transactions or private financing arrangements in order to optimize maturities and cost of capital. See “Risk Factors—Risks Related to Our Business and Operations—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 regarding interest rates and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” and “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Registered Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.”
Market Opportunity
Our royalty and working interest acquisitions generally focus on specific subsets of mineral and leasehold assets in the United States. From a market perspective, we focus on highly attractive and defined basins, currently serviced by top-tier operators, with assets that we believe will generate high near-term cash flow. All the assets we seek to acquire are purchased at what management believes are attractive price points and have a liquidity profile that is desirable in the secondary market. We generally seek to acquire assets that have a near-term payback and long-term residual cash flow upside.
Business Strategy
Our three-pronged strategy centers around (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets for the purpose of exploration, development, production, and sale of crude oil, natural gas, natural gas liquids, and other byproducts conducted through our subsidiaries. We execute our strategy through Phoenix Energy and three of our subsidiaries. PhoenixOp was formed in January 2022 to drill, complete, and operate wells in the United States. Firebird Services was formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp. Firebird Marketing was formed in March 2025 to take title to oil at or near the wellhead and market production to third-party purchasers. It manages commercial and logistical activities related to the sale of hydrocarbons, including transportation coordination, blending and quality optimization, scheduling, and counterparty negotiations, and it assumes market, operational, and credit risks related thereto. In return, Firebird Marketing may earn marketing margins based on market conditions and its ability to optimize sales execution.
Direct Drilling Operations
We currently run our own direct drilling activities through PhoenixOp. Throughout 2024 and 2025, we increased the extent to which we run our own direct drilling operations and expect to continue to grow our drilling activities going forward. We intend to actively drill and develop select assets in an effort to maximize value and resource potential, and we will generally seek to increase our production, reserves, and cash flow from direct drilling operations
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over time. We have identified a number of potential drilling locations that we believe have the potential for attractive growth and opportunities. In accordance with that business plan, we acquired our third drilling rig in April 2025.
As we rely more on our own direct drilling operations, our capital expenditures and operating expenses have also increased significantly, and we expect this increase in capital and operating expenses to continue as compared to our previous business model, which relied heavily on royalty and working interest acquisitions. As such, in 2026, we expect to have increased needs for additional capital in excess of cash flows from operating activities in order to fund the growth of our business and the development of our reserves. We expect to supplement operating cash flow with external capital sources to fund the planned expansion of our operated drilling program. The pace of drilling activity is discretionary and may be adjusted based on commodity prices, capital market conditions, and internal rate-of-return thresholds. Although we believe that running our own direct drilling operations will require significantly greater funds than partnering with a third-party operator, we believe that this strategy will provide greater control of cash flow, increased revenue, and larger potential for shorter payback periods as compared to returns on royalty assets and working interest assets. We expect that this ongoing shift in our business model will allow us to capture more of the upside from the use of our specialized software system. As of December 31, 2025, we estimate that our direct drilling operations will require approximately $161.6 million in additional capital throughout 2026 in order to achieve our intended business plan. We expect that these capital needs will be met in the near to medium term by capital contributions to PhoenixOp by us, which we expect to fund from time to time in varying amounts through a combination of cash from operations and the proceeds from loans and offerings of debt and equity securities. As of December 31, 2025, we had contributed approximately $371.3 million in cash and $67.2 million in lease assets to PhoenixOp. As of December 31, 2025, after giving effect to an increase in March 2026 in the amount permitted to be borrowed under the Adamantium Loan Agreement by $200.0 million, we had $253.5 million available for us to borrow under the Adamantium Loan Agreement (assuming Adamantium is able to issue the corresponding amount of Adamantium Securities). We also continue to issue August 2023 506(c) Bonds and Registered Notes, and, as of December 31, 2025, after giving effect to an increase in March 2026 of the offering amount of the August 2023 506(c) Bonds by $500.0 million, we had $978.9 million and $715.2 million of additional headroom until we reach the announced target offering amounts of $2.0 billion of August 2023 506(c) Bonds and $750.0 million of Registered Notes. Our funding of additional amounts to PhoenixOp will not be subject to specific milestones or triggering events, but instead will be guided by our business judgment in order to execute on our intended business plan. We intend to make such capital contributions to PhoenixOp until such time as PhoenixOp procures its own financing, if any, or has sufficient cash from operations to operate without supplemental financing from us. PhoenixOp is currently a borrower under certain of our loan agreements, including the Fortress Credit Agreement and Adamantium Loan Agreement, and could borrow amounts under such agreements directly. Although we have issued over $346.5 million of Adamantium Securities to date, there can be no assurance that we will be successful in issuing additional Adamantium Securities and utilizing then-available commitments under the Adamantium Loan Agreement. There is currently no committed amount of additional financing available under the Fortress Credit Agreement. See “Risk Factors—Risks Related to Our Business and Operations—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 regarding interest rates and otherwise.”
Leases are contributed to PhoenixOp at a value equal to our cost of acquisition of the contributed asset, and we anticipate contributing additional oil and gas properties to PhoenixOp in the future. Leases are generally contributed in order for PhoenixOp to operate extraction activities on such assets with the requisite title and permissions. We expect to only contribute oil and gas properties to PhoenixOp that are located in an area where we own or lease enough continuous productive acreage to support meaningful mineral extraction activities. Whether and when we have properties we decide to contribute to PhoenixOp will depend on, among other things, our ability to acquire properties from multiple owners, the amount and quality of mineral reserves discovered on such properties, the presence of or proximity to third-party operators with existing extraction activities, and the suitability of the area’s topography for drilling and operating producing wells. See “Risk Factors—Risks Related to Our Business and Operations—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.”
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Royalty and Working Interest Acquisitions
For our royalty and working interest acquisitions, we have developed a process for the identification, acquisition, and monetization of assets. Below is a general illustration of our process:
Separate from the ordinary royalty income assets, we maintain a structural discipline to participate in non-operated working interests, in part for their tax benefits. Due to favorable U.S. Internal Revenue Service (the “IRS”) treatment, marrying this asset class to our pure royalty income creates an augmented “write off” strategy whereby the balanced portfolio effectively creates little to no annual taxable income. Functionally, the transactions we enter into are similar to traditional real estate transactions with respect to the mechanics. A seller agrees to sell to us, a purchase and sale agreement is executed, earnest money is conveyed, and manual diligence and title review is conducted as an audit function prior to closing. Upon closing, the funds are conveyed to the seller and the title is recorded by us in the applicable jurisdiction. Assets can produce for upwards of 20 years; however, there is a considerable regression/depletion curve over the life of the asset. As such, we tend to focus on wells that have recently begun producing or are likely to have new production in the near term. We focus on a closed-loop process from discovery to acquisition to long-term balance sheet ownership. We believe the recurring nature of these cash flows will allow for considerable scale without material increases in fixed overhead.
Our Specialized Software System
Our software system is designed to be scalable and process inputs from a variety of internal and external sources, and supports our ability to identify, analyze, underwrite, and formally transact in the purchasing of oil and gas assets. Our software system operates across three key facets of our business:
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While the data inputs utilized by our software system are largely based on public information, considerable customization and coding has been undertaken to generate a system that we can successfully leverage in our business. This software was designed and built by us to address our specific needs, and we are not aware of a similar competitive product. We rely on trade secret laws to protect our software system and do not own any registered copyright, patent, or other intellectual property rights regarding our software. However, we believe the investment of significant monetary and intellectual resources have created a system that would be difficult to replicate. We currently have no intention of licensing or selling our software. See “Risk Factors—Risks Related to Legal, Regulatory, and Environmental Matters—We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology.”
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 December 31, 2025, we owned mineral, royalty, and working interests in 7,768 productive wells, the majority of which are oil wells that also produce natural gas and NGL.
As of December 31, 2025, we had 203 wells that fall under our “wells in progress” (“WIP”) category, and we had 56.7 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.
Drilling Results
In the year ended December 31, 2025, the E&P operators of our properties, including PhoenixOp, drilled 508 gross and 62.9 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 463 and 1,965 gross and 43.2 and 19.2 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the years ended December 31, 2024 and 2023, respectively.
Included in our total drilled wells figures, as of December 31, 2025, PhoenixOp had drilled a total of 97 gross and 86.7 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 19 gross and 19 net saltwater disposal wells, and had 61 gross and 45.0 net development wells in progress as of December 31, 2025.
As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
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Wells
As of December 31, 2025, we owned mineral, royalty, and working interests in 7,768 total gross wells and 143.2 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of December 31, 2025:
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Well Count |
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Oil |
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Gas |
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Gross |
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Net |
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Gross |
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Net |
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Basin or Producing Region |
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Bakken/Williston Basin |
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4,537 |
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120.2 |
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3 |
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0.0 |
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Denver-Julesburg Basin/Rockies/Niobrara |
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1,495 |
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17.7 |
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6 |
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0.0 |
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Permian Basin |
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740 |
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1.4 |
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1 |
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0.0 |
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Other |
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492 |
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1.3 |
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494 |
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2.6 |
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Total |
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7,264 |
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140.6 |
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504 |
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2.6 |
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Acreage of Mineral and Working Interests
The following tables set forth information relating to the acreage underlying our mineral and working interests as of December 31, 2025:
Acreage of Mineral Interest
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Net Royalty Acres |
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Developed |
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Undeveloped |
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Total |
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Basin |
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Bakken/Williston Basin |
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23,637 |
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83,596 |
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107,233 |
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Denver-Julesburg Basin/Rockies/Niobrara/PRB |
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5,398 |
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12,526 |
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17,924 |
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Permian Basin |
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657 |
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354 |
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1,011 |
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Other |
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470 |
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435,680 |
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436,150 |
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Total Net Royalty Acres |
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30,162 |
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532,156 |
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|
562,318 |
|
|
|
Gross Royalty Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
620,898 |
|
|
|
1,003,432 |
|
|
|
1,624,330 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
125,002 |
|
|
|
377,038 |
|
|
|
502,040 |
|
Permian Basin |
|
|
94,083 |
|
|
|
24,603 |
|
|
|
118,686 |
|
Other |
|
|
17,579 |
|
|
|
2,216,297 |
|
|
|
2,233,876 |
|
Total Gross Royalty Acres |
|
|
857,562 |
|
|
|
3,621,370 |
|
|
|
4,478,932 |
|
Acreage of Working Interest
|
|
Net Mineral Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
57,071 |
|
|
|
269,068 |
|
|
|
326,139 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
4,231 |
|
|
|
36,438 |
|
|
|
40,669 |
|
Permian Basin |
|
|
28 |
|
|
|
36 |
|
|
|
64 |
|
Other |
|
|
259 |
|
|
|
259,467 |
|
|
|
259,725 |
|
Total Net Mineral Acres |
|
|
61,589 |
|
|
|
565,008 |
|
|
|
626,597 |
|
12
Table of Contents
|
|
Gross Mineral Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
304,704 |
|
|
|
874,022 |
|
|
|
1,178,726 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
44,222 |
|
|
|
236,001 |
|
|
|
280,223 |
|
Permian Basin |
|
|
7,680 |
|
|
|
1,280 |
|
|
|
8,960 |
|
Other |
|
|
15,872 |
|
|
|
1,309,568 |
|
|
|
1,325,440 |
|
Total Gross Mineral Acres |
|
|
372,478 |
|
|
|
2,420,871 |
|
|
|
2,793,349 |
|
Acreage Expirations
As of December 31, 2025, we have 442,168 gross and 61,807 net working interest acres expiring through the end of 2027, with an additional 470,155 gross and 57,027 net working acres expiring in 2028, and 537,673 gross and 80,631 net working interest acres expiring in 2029. The remaining 398,038 gross and 71,270 net working interest acres expire in years 2030 and beyond.
Evaluation and Review of Estimated Proved and Probable Reserves
We use the term “probable reserves” herein to refer to those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The probable reserves disclosed herein have been quantified using deterministic methods and, when combined with proved reserves, have at least a 50% probability that actual quantities recovered will equal or exceed the proved plus probable reserves estimates in accordance with Rule 4-10(a)(18) of Regulation S-X. The probable reserves are adjacent to quantifiable proved reserves but where data control is present but is less certain. Our probable reserves are assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Our probable reserves are also assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. The proved plus probable estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
We use the term “proved reserves” herein to refer to quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data, and reliable technology established a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data, and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the
13
Table of Contents
reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
In order to establish the appropriate level of reserve categories and estimates to assign to our properties, we utilize modern geologic and engineering technologies, some of which are proprietary and some of which are publicly available. These technologies include, but are not limited to, drilling and completions data, flowback data, productivity results, pressure performance, mapping of geologic characteristics taken from open hole logs, cased hole logs, gamma ray logs, measurement while drilling logs, electric logs, and seismic surveys.
The proved and probable reserves estimates reported herein are as of December 31, 2025, 2024, and 2023. The technical persons primarily responsible for preparing the estimates disclosed herein each have over 15 years of industry experience. Each meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines. Until his resignation on November 3, 2025, Brandon Allen, our former Chief Operating Officer, was primarily responsible for overseeing the preparation of the reserves estimation. Following Brandon Allen's resignation, Kyle Beam, our Manager of Corporate Reserves, has been primarily responsible for overseeing the preparation of the reserves estimation. Mr. Beam has over 20 years of experience in the oil and gas industry and is licensed in Colorado and Wyoming as a professional petroleum engineer.
Proved and probable reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2025, 2024, or 2023, as applicable. Average prices for the 12-month periods were as follows: the U.S. New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) crude oil spot price of $66.01 per Bbl as of December 31, 2025, adjusted by lease or field for quality, transportation fees, and market differentials, and a Henry Hub natural gas spot price of $3.387 per MMBtu as of December 31, 2025, adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.
We estimate the quantity or perceived cash flow of proved and probable undeveloped reserves for financial reporting purposes in accordance with the five-year rule as set forth by the SEC. Most proved undeveloped properties are operated by our subsidiary, PhoenixOp, whereby we and PhoenixOp have the property on the most current drill schedule. Non-operated proved and probable undeveloped properties represent properties that we have high confidence will be converted to producing properties within five years based on our diligence and review of public and non-public data sources. As it relates to a majority of our mineral and non-operated interest holdings, we do not always have the ability to accurately estimate when undeveloped reserves may be extracted and instead take a conservative approach whereby we only classify such reserves as proved when such reserves are either currently producing or where we have knowledge of a close date of extraction, such as upon our receipt of a notice from the operators of such reserves providing a specific timeframe for near-term production. We classify the remaining reserves as probable reserves. For example, for probable undeveloped reserves, we have a high confidence that the properties are on a development plan and/or will be converted to producing properties within the next five years based on, among other factors, our discussions with service providers, the location of nearby drilling rigs, permits obtained by the operators that are generally valid for one to two years, and the terms of the respective leases, which typically expire within five years.
Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves, and the future cash flows related to such estimates, and should not be summed arithmetically with estimates of proved reserves, and the future cash flows related to such estimates. When producing an estimate of the amount of natural gas and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on
14
Table of Contents
production history, results of additional exploration and development, price changes, and other factors. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
The reserves information in this disclosure represents only estimates. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, results of drilling, testing, and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
In addition, the preparation of our proved and probable reserve estimates are completed in accordance with internal control procedures, including the following:
15
Table of Contents
Oil, Natural Gas, and NGL Reserves
The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:
|
|
As of December 31, |
|
|||||||||
|
|
2025(1)(2) |
|
|
2024(2)(3) |
|
|
2023(2)(4) |
|
|||
Estimated proved developed reserves |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
39,367,935 |
|
|
|
18,624,758 |
|
|
|
7,124,194 |
|
Natural gas (Mcf) |
|
|
32,222,398 |
|
|
|
20,819,874 |
|
|
|
12,250,285 |
|
Natural gas liquids (Bbl) |
|
|
6,882,740 |
|
|
|
2,848,355 |
|
|
|
1,514,761 |
|
Total (Boe)(6:1)(5) |
|
|
51,621,074 |
|
|
|
24,943,092 |
|
|
|
10,680,669 |
|
Estimated proved undeveloped reserves |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
49,888,499 |
|
|
|
31,197,795 |
|
|
|
24,925,841 |
|
Natural gas (Mcf) |
|
|
27,916,131 |
|
|
|
17,491,089 |
|
|
|
19,565,808 |
|
Natural gas liquids (Bbl) |
|
|
7,451,608 |
|
|
|
4,753,257 |
|
|
|
6,648,747 |
|
Total (Boe)(6:1)(5) |
|
|
61,992,797 |
|
|
|
38,866,234 |
|
|
|
34,835,556 |
|
Estimated proved reserves |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
89,256,434 |
|
|
|
49,822,553 |
|
|
|
32,050,035 |
|
Natural gas (Mcf) |
|
|
60,138,529 |
|
|
|
38,310,963 |
|
|
|
31,816,093 |
|
Natural gas liquids (Bbl) |
|
|
14,334,348 |
|
|
|
7,601,612 |
|
|
|
8,163,508 |
|
Total (Boe)(6:1)(5) |
|
|
113,613,871 |
|
|
|
63,809,326 |
|
|
|
45,516,226 |
|
Percent proved developed |
|
|
45 |
% |
|
|
39 |
% |
|
|
23 |
% |
Estimated probable undeveloped reserves |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
178,532,093 |
|
|
|
107,769,309 |
|
|
|
74,877,268 |
|
Natural gas (Mcf) |
|
|
105,888,056 |
|
|
|
134,083,603 |
|
|
|
88,184,111 |
|
Natural gas liquids (Bbl) |
|
|
31,779,646 |
|
|
|
— |
|
|
|
— |
|
Total (Boe)(6:1)(5) |
|
|
227,959,749 |
|
|
|
130,116,576 |
|
|
|
89,574,620 |
|
16
Table of Contents
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, a 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 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
17
Table of Contents
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
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 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. We delivered 1.0 million barrels of crude oil during the year ended December 31, 2025, and the remaining aggregate commitment under the contract as of December 31, 2025 is approximately 1.2 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.
Select Production and Operating Statistics
The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:
|
|
For the Years Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Production Data: |
|
|
|
|
|
|
|
|
|
|||
Bakken |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
7,831,787 |
|
|
|
3,022,810 |
|
|
|
943,930 |
|
Natural gas (Mcf) |
|
|
2,176,128 |
|
|
|
1,301,782 |
|
|
|
1,123,859 |
|
Natural gas liquids (Bbl) |
|
|
576,561 |
|
|
|
270,219 |
|
|
|
88,762 |
|
Total (Boe)(6:1)(1) |
|
|
8,771,036 |
|
|
|
3,509,992 |
|
|
|
1,220,003 |
|
Average daily production (Boe/d)(6:1) |
|
|
24,030 |
|
|
|
9,590 |
|
|
|
3,342 |
|
All Properties |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
8,641,089 |
|
|
|
3,830,461 |
|
|
|
1,446,928 |
|
Natural gas (Mcf) |
|
|
3,427,154 |
|
|
|
2,979,341 |
|
|
|
2,152,939 |
|
Natural gas liquids (Bbl) |
|
|
712,056 |
|
|
|
415,363 |
|
|
|
201,454 |
|
Total (Boe)(6:1)(1) |
|
|
9,924,337 |
|
|
|
4,742,381 |
|
|
|
2,007,205 |
|
Average daily production (Boe/d)(6:1) |
|
|
27,190 |
|
|
|
12,993 |
|
|
|
5,499 |
|
Average Realized Prices: |
|
|
|
|
|
|
|
|
|
|||
Bakken |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
$ |
64.02 |
|
|
$ |
71.77 |
|
|
$ |
71.43 |
|
Natural gas (Mcf) |
|
$ |
2.33 |
|
|
$ |
2.12 |
|
|
$ |
3.47 |
|
Natural gas liquids (Bbl) |
|
$ |
20.76 |
|
|
$ |
23.53 |
|
|
$ |
26.70 |
|
All Properties |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
$ |
62.45 |
|
|
$ |
68.49 |
|
|
$ |
73.10 |
|
Natural gas (Mcf) |
|
$ |
2.31 |
|
|
$ |
1.86 |
|
|
$ |
3.15 |
|
Natural gas liquids (Bbl) |
|
$ |
20.90 |
|
|
$ |
25.22 |
|
|
$ |
27.50 |
|
Average Unit Cost per Boe (6:1): |
|
|
|
|
|
|
|
|
|
|||
All Properties |
|
|
|
|
|
|
|
|
|
|||
Operating costs, production and ad valorem taxes |
|
$ |
18.99 |
|
|
$ |
16.11 |
|
|
$ |
16.18 |
|
Operating costs excluding taxes |
|
$ |
14.38 |
|
|
$ |
10.75 |
|
|
$ |
10.86 |
|
Percentage of revenue(2) |
|
|
33.5 |
% |
|
|
26.4 |
% |
|
|
16.7 |
% |
18
Table of Contents
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 $177.9 million, $86.0 million, and $34.2 million for the years ended December 31, 2025, 2024, and 2023, respectively. On a per unit basis, depletion expense was $17.92 per Boe, $18.13 per Boe, and $17.06 per Boe for the years ended December 31, 2025, 2024, and 2023, respectively. The decrease in our depletion rate for the year ended December 31, 2025 compared to 2024 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 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 depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.
PV-10
|
|
For the Years Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
PV-10 (estimated proved developed reserves) |
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
PV-10 (estimated proved undeveloped reserves) |
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
PV-10 (estimated total proved reserves) |
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
We calculate PV-10 as the discounted future net cash flows attributable to our proved oil and natural gas reserves before income taxes, discounted at 10% annually. PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable generally accepted accounting principles in the United States (“GAAP”) financial measure, because it is calculated on a pre-tax basis. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, and is useful for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities.
Because the Company is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro-rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows. Notwithstanding the foregoing, we believe that the presentation of PV-10 is useful to investors because it is a commonly utilized measure in our industry for assessing the value of reserves.
PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our oil and natural gas reserves.
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The following table includes a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:
|
|
For the Years Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Estimated proved developed reserves: |
|
|
|
|
|
|
|
|
|
|||
Standardized measure of discounted future net cash flows |
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
Estimated proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|||
Standardized measure of discounted future net cash flows |
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
Estimated total proved reserves: |
|
|
|
|
|
|
|
|
|
|||
Standardized measure of discounted future net cash flows |
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
Our E&P Operators
Our management team strives to acquire mineral and royalty interests in properties with top-tier third-party E&P operators. We seek third-party E&P operators that are well-capitalized, have a strong operational track record, and we believe will continue to produce through the application of the latest drilling and completion techniques across our mineral and royalty interests. Over 100 third-party E&P operators are currently producing oil and gas at our assets. As of December 31, 2025, our top ten third-party E&P operators operate on 15.2% of our NRAs.
Industry Operating Environment
The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change, and the environment, political and social developments in the Middle East and Russia, demand in Asian and European markets, and the extent to which members of Organization of the Petroleum Exporting Countries (“OPEC”) and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas because it is a primary heating source.
Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that our assets can economically produce. Among other things, drilling operations and related activities can be significantly impacted by the accuracy of the estimation of reserves and the effect on those reserves of fluctuating market prices. If commodity prices decline, the cost of developing, completing, and operating a well may not decline in proportion to the prices that are received for the production, resulting in higher operating and capital costs as a percentage of revenues. While lower commodity prices may reduce the future net cash flow from operations of the assets in which we invest, we expect to have sufficient liquidity to continue participation in development of our oil and gas properties.
Competition
The oil and gas industry is intensely competitive, and we compete with other oil and natural gas E&P companies, some of which have substantially greater resources than we have and may be able to pay more for exploratory prospects and productive oil and natural gas properties, and competition for our target asset classes is subject to increase in the future. Our larger or more integrated competitors may be better able to absorb the burden of existing, as well as any changes to, federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to acquire additional assets in the future is dependent on the success of our software platform, our ability and resources to evaluate and select suitable properties, and our ability to consummate transactions in this highly competitive environment.
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Marketing and Customers
The market for oil and natural gas that will be produced from our assets depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.
Our oil and natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our third-party operating and service partners to market and sell our production. Our operating partners include a variety of E&P companies, from large, publicly-traded companies to small, privately-owned companies. Our service partners include a variety of oil and natural gas gathering, transportation, processing, and marketing companies. We do not believe the loss of any single operator or service partner would have a material adverse effect on the Company as a whole.
Seasonality
Winter weather events and conditions, such as ice storms, freezing conditions, droughts, floods, and tornados, breeding and nesting seasons, and lease stipulations can limit or temporarily halt our and our operating partners’ drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our and our operating partners’ operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our and our operating partners’ operations.
Title to Properties
Prior to completing an acquisition of mineral and royalty interests, we perform due diligence title reviews on a majority of tracts to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount, and encumbrances or other related burdens. Said title review consists of a patent to present title search on the prospective tract and a “grantor/grantee” search of the prospective seller in county records, in addition to a lien/judgment search related to the seller’s ownership.
In addition to our initial title work and due diligence title review, PhoenixOp (in properties in which we have direct drilling operations) and our third-party E&P operators (in other properties) will conduct a thorough title examination prior to leasing and/or drilling a well and paying out the royalty owner. Should an E&P operator’s title work uncover any further title defects, either we or the third-party E&P operator will perform curative work with respect to such defects. A third-party E&P operator generally will not pay out royalty payments on the property until any material title defects on such property have been cured.
We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests, and other burdens, easements, restrictions, or minor encumbrances customary in the crude oil and natural gas industry, we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.
Governmental Regulation and Environmental Matters
Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas E&P industry as a whole, including those associated with E&P operators and other owners of working interests in crude oil and natural gas properties. The legislation and regulation affecting the crude oil and natural gas industry are under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.
Environmental Matters
Crude oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which we own mineral interests, which could materially adversely affect our business and prospects.
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Numerous federal, state, and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon the E&P operators of our properties, including PhoenixOp regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. However, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects.
Non-Hazardous and Hazardous Waste
The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes and regulations promulgated thereunder affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development, and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with E&P of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Any changes in the laws and regulations could have a material adverse effect on the E&P operators of our properties’ capital expenditures and operating expenses, including those of PhoenixOp, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.
Remediation
The Comprehensive Environmental, Response, Compensation and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons who disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint, and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition, and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position, or financial condition.
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Water Discharges
The Clean Water Act (“CWA”), the Safe Drinking Water Act (the “SDWA”), the Oil Pollution Act of 1990 (the “OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years, with different definitions proposed under the Obama and Trump Administrations. Both of these definitions have been subject to litigation. In January 2023, the EPA and the U.S. Army Corps of Engineers (the “Corps”) released a final revised definition of “waters of the United States” founded upon a pre-2015 definition and included updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023, the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as waters of the United States. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023. However, due to the injunction of the January 2023 rule, the implementation of the September 2023 rule currently varies by state. In November 2025, the EPA and Corps announced the release of the proposed rule revising the definition of “waters of the United States,” guided by the Sackett decision. In January 2026, the Corps published revised Nationwide Permits (“NWP”). To the extent the implementation of a new final rule related to the definition of “waters of the United States” results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our operators, including PhoenixOp. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain crude oil and natural gas E&P facilities to obtain individual permits or coverage under general permits for storm water discharges, and, in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.
The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.
Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, for the E&P operators of the acreage underlying our mineral interests, including PhoenixOp.
Air Emissions
The Clean Air Act of 1970 (as amended, the “CAA”) and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests. In addition, federal and state regulatory agencies can impose administrative, civil, and criminal penalties for noncompliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.
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Climate Change
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. The future of any climate-related regulations and any enforcement of such regulations at the federal level remains unclear in light of recent announcements and actions by the Trump Administration, including the EPA’s proposed rule to repeal the GHG emissions standards for fossil fuel-fired electric generating units that was issued on June 11, 2025, the EPA’s internal memorandum establishing a “compliance first” focus for all environmental compliance effective December 5, 2025, and the EPA’s rescission of the 2009 GHG endangerment finding and repeal of motor vehicle GHG emission standards under the CAA on February 12, 2026. The final rule is subject to litigation, and we cannot predict the outcome of such litigation or any potential impacts at this time.
In the United States, since the Infrastructure Investment and Jobs Act and the Inflation Reduction Act of 2022 (“IRA 2022”), no comprehensive climate change legislation has been implemented at the federal level. Although former President Biden’s administration highlighted addressing climate change as a priority and issued several executive orders to that effect, President Trump’s administration has taken a different stance, and has revoked many of former President Biden’s executive orders and imposed a regulatory freeze. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and, together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. However, in response to former President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc, in December 2023. Under those rules, states would have two years to prepare and submit their plans to impose methane emissions controls on existing sources. However, the EPA issued a direct interim final rule in July 2025 and a final rule in December 2025 that pushed the substantive deadlines in OOOOb and OOOOc back to January 2027. On November 12, 2024, the EPA finalized the methane emissions charge rule, implementing the IRA 2022. On March 14, 2025, the U.S. Congress signed legislation that eliminated the EPA’s regulations in support of the waste emissions charge and, therefore, the future of this rule remains unclear. Additionally, while the U.S. Congress has not repealed the IRA 2022 wholesale, it has amended the IRA 2022 through the One Big Beautiful Bill Act (the “OBBBA”), signed on July 4, 2025, which repealed the CAA section authorizing the GHG Reduction Fund and delayed the methane emissions charge fee collection to 2034.
The presumptive standards established under the methane emissions charge rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the EPA of large methane emissions events, triggering certain investigation and repair requirements. Twenty-three states have filed a lawsuit challenging the methane emissions charge rule, and the change in U.S. presidential administration provides additional uncertainty as to the future of the methane emissions charge. Compliance with these rules may affect the amount oil and gas companies owe under the IRA 2022, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. Compliance with the EPA’s new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. Failure to comply with the requirements of the EPA’s new rules and the methane fee could adversely affect costs of compliance and operations and result in the imposition of substantial fines and penalties, as well as costly injunctive relief. On March 14, 2025, the U.S. Congress signed legislation that eliminated the EPA’s regulations in support of the waste emissions charge and, further, with the OBBBA, the rule currently will be delayed in application until 2034.
Separately, various states and groups of states have adopted or are considering adopting legislation, regulation, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting
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and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the agreement crafted during the United Nations climate change conference in Paris, France, in December 2015 (the “Paris Agreement”) requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. Although former President Biden recommitted the United States to the Paris Agreement during his presidency and, in April 2021, announced a goal of reducing the United States’ emissions by 50 to 52% below 2005 levels by 2030, President Trump signed an executive order that directed the United States to withdraw from the Paris Agreement and from any commitments made under the United Nations Framework Convention on Climate Change (“UNFCCC”). In January 2026, the United States officially withdrew from the Paris Agreement. The Trump Administration’s stance makes it unclear whether the Global Methane Pledge announced by the United States and the European Union at the 26th Conference of the Parties (“COP”) to the UNFCCC in Glasgow in November 2021—an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector—will move forward. In December 2023, the United Arab Emirates hosted the 28th COP where parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly, and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. In November 2024, Azerbaijan hosted the 29th COP, which concluded with an agreement calling on developed countries to deliver at least $300 billion per year to developing countries by 2035 to drastically reduce GHG emissions and protect lives and livelihoods from the impacts of climate change. In November 2025, Brazil hosted the 30th COP, with no official participation by or representatives from the United States. The full impact of these various orders, pledges, agreements, and actions cannot be predicted at this time.
Whereas on January 27, 2021, former President Biden’s administration had called for restrictions on leasing on federal land, and had issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors, the new Trump Administration has revoked many such related rules and executive orders focusing on GHG emissions and fossil fuel energy regulations. For example, on January 21, 2025, the Trump Administration lifted the former administration’s pause on liquefied natural gas exports. However, we cannot predict whether and to what extent the Trump Administration will continue to act favorably to the energy sector.
Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
Historically there have also been increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, in October 2023, the U.S. Federal Reserve (“Federal Reserve”), Office of the Comptroller of the Currency, and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. The limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities. Additionally, on March 6, 2024, the SEC adopted rules to enhance and standardize climate-related disclosures by public companies and in public offerings. However, on April 4, 2024, the SEC voluntarily stayed implementation of these rules pending completion of judicial review of consolidated challenges to the rules by the U.S. Court of Appeals for the Eighth Circuit. On September 12, 2025, the Eighth Circuit placed the consolidated cases in abeyance while the SEC determines whether to defend, revise, or rescind the rules. Although the application and viability of the proposed rules remain stayed, any adoption of such rules either by the Trump Administration or a future administration may result in additional costs to comply with any such disclosure requirements, alongside increased costs of and restrictions on access to capital.
The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and
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natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks may result in our oil and natural gas operators restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators, including PhoenixOp, and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water-use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Extreme weather conditions can interfere with production and increase costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs. However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that establish new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years.
In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.
Several states where we operate, including North Dakota, Montana, Utah, Texas, Colorado, and Wyoming, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Railroad Commission (the “Texas RRC”) has previously issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.
In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, in November 2020, the Colorado Oil and Gas Conservation Committee (the “COGCC”), as part of Senate Bill 181’s (“SB 181”) mandate for the COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. The Colorado Department of Public Health and the Environment also finalized rules related to the control of emissions from certain pre-production activities; namely, curbing methane emissions by setting limits of per 1,000 barrels of oil equivalent produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of SB 181 could adversely impact our revenues and future production from our properties.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing-related activities, particularly the disposal of produced water in underground injection wells, and the
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increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Texas RRC published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. The Texas RRC has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In late 2021, the Texas RRC issued a notice to operators of disposal wells in the Midland area to reduce saltwater disposal well actions and provide certain data to the Texas RRC. In December 2021, the Texas RRC suspended all disposal well permits to inject oil and gas waste within the boundaries of the Gardendale Seismic Response Area. Relatedly, in March 2022, the Texas RRC began implementation of its Northern Culberson-Reeves Seismic Response Area Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. From November 8 through December 17, 2023, the TexNet Seismic Monitoring Program reported seven earthquakes with magnitudes greater than 3.5 and, in April 2024, a 4.4 magnitude earthquake was recorded in the Stanton Seismic Response Area, an area where the Texas RRC is also monitoring seismic activity linked to disposal of saltwater. In January 2024, the RRC banned saltwater disposal injection in the Northern Culberson-Reeves Seismic Area, which applied to 23 disposal wells in the area. As a result of these developments, our operators may be required to curtail operations or adjust development plans, which may adversely impact our business. In May 2024, the EPA announced it would review the Texas RRC’s oversight of disposal wells used for injecting oil drilling wastewater and carbon dioxide into the ground and remains in review. In November 2025, the EPA approved Texas for Class VI primacy under the SDWA, making Texas RRC the primary permitting and enforcement authority for geologic carbon dioxide sequestration wells in Texas, except on Native American lands where the EPA remains the permitting authority. The EPA will continue to oversight the state program. The USGS has identified six states with the most significant hazards from induced seismicity, including Texas and Colorado. In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the E&P operators of our properties, including PhoenixOp, and on their waste disposal activities.
If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting, and recordkeeping obligations, plugging and abandonment requirements, and to attendant permitting delays and potential increases in costs. Such legislative changes could cause E&P operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by E&P operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Endangered Species Act
The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions, or bans in the affected areas. As part of a stipulated settlement agreement in a case challenging its failure to timely make a 12-month finding on a petition to list the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, the United States Fish and Wildlife Service (the “FWS”). In June 2024, the FWS issued a final rule listing the dunes sagebrush lizard as endangered under the ESA. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. In November 2022, following an extensive review, the FWS listed the northern distinct population segment of the Lesser Prairie Chicken, encompassing southeastern Colorado, southcentral to western Kansas, western Oklahoma, and the northeast Texas Panhandle, as threatened, and the southern district population segment, covering eastern New Mexico and the southwest Texas Panhandle, as endangered. The FWS listing decisions for both the lesser prairie chicken and the dunes sagebrush lizard are subject to ongoing litigation in the U.S. District Court for the Western District of Texas.
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To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. Additionally, in April 2025, the FWS issued a proposed rule to change the definition of “harm” under the ESA. In November 2025, the FWS also proposed additional ESA rulemakings to roll back or revise 2024 regulations addressing Section 7 consultations, the Section 4(d) blanket rule for threatened species, and critical habitat exclusions; those proposals likewise remain pending at the proposal stage. If finalized, the rule may significantly narrow federal habitat protections for endangered species across the United States.
Employee Health and Safety
Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the “OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens.
Other Regulation of the Crude Oil and Natural Gas Industry
The crude oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.
The availability, terms and conditions, and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions, and rates for interstate transportation, storage, and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.
We cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate, and NGL are not currently regulated and are made at market prices.
Drilling and Production
The operations of the E&P operators of our properties, including PhoenixOp, are subject to various types of regulation at the federal, state, and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
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State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the E&P operators of our properties can produce from our wells or limit the number of wells or the locations at which E&P operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil, natural gas, and NGL within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or limit the number of locations E&P operators can drill.
Federal, state, and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and site restoration in areas where the E&P operators of our properties operate. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning, and site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation
FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”
Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the E&P operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues such E&P operators receive for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers, and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open-access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the E&P operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the E&P operators of our properties produce.
Historically, the natural gas industry was more heavily regulated; therefore, we cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Crude Oil Sales and Transportation
Crude oil sales are affected by the availability, terms, and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act, and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open-access standard, common carriers must offer service to all similarly situated
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shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services by E&P operators of our properties will not materially differ from our competitors’ access to crude oil pipeline transportation services.
Certain State Regulations and Developments
North Dakota
On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of Dakota Access Pipeline’s (“DAPL”) easement from the Corps and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement but declined to require the pipeline to shut down while an Environmental Impact Statement (“EIS”) is prepared. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. Following the denial of a rehearing en banc by the Court of Appeals for the District of Columbia, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply, although in February 2022, the U.S. Supreme Court denied certiorari, declining to hear the appeal. The pipeline continues to operate pending completion of the Environmental Impact Statement, which the Corps released in September 2023. In December 2025, the Corps released the final EIS identifying a preferred alternative to grant the easement with additional conditions but has not yet issued a Record of Decision. Additional lawsuits challenging the legality of the DAPL have been filed by various stakeholders. We cannot determine when or how these or future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, we may be adversely affected by increased transportation costs, well shut ins, and future production, negatively impacting our revenue costs.
Montana
In April 2020, a Montana federal judge vacated the Corps’ NWP 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the FWS under the ESA regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order went on appeal in the Ninth Circuit Court of Appeals. The United States Supreme Court narrowed the applicability of the order to the Keystone XL pipeline pending the outcome of the Ninth Circuit’s decision, and in May 2021, the Biden Administration argued that the suit was moot given the discontinuation of the Keystone XL pipeline. In March 2022, the Corps announced its formal review of NWP 12. In January 2026, the Corps finalized the 2026 NWP, effective March 15, 2026 through March 15, 2031, reissuing NWP 12 as the primary general permit for oil and natural gas pipeline activities in waters of the United States. Project-specific use of these permits remains subject to regional conditions and state or tribal CWA Section 401 water quality certifications. Ongoing or future litigation and certification decisions could affect the availability, timing, or conditions of NWP 12 in some jurisdictions, which may prevent the advancement of our oil and gas infrastructure projects.
In December 2024, the Montana Supreme Court affirmed a lower court decision in Held v. State of Montana, holding that the right to a clean and healthful environment under the Montana Constitution includes a stable climate system, and that the law at question banning state agencies from weighing the impact of climate change and GHG emissions in environmental reviews was unconstitutional under state law. The policy impacts of the ruling remain unclear; however, it may lead to adverse changes in the permitting process for oil and gas development in Montana, and may lead to further lawsuits, which may negatively impact our operations in the state.
Utah
In recent years, Utah has experienced persistent and severe drought conditions. Various local governments in Utah have implemented water restrictions. Water management and our access to water, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations due to water’s significance in shale oil and natural gas development. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. Our E&P operators may use water supplied from various local and regional sources to support operations like steam injection in certain fields. While our E&P operators’ production to date has not been materially impacted by restrictions on
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wastewater disposals or access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.
Texas
Texas regulates the drilling for, and the production, gathering, and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of crude oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of crude oil and natural gas resources.
States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on our properties and the number of wells or locations the E&P operators of our properties can drill.
The petroleum industry is also subject to compliance with various other federal, state, and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not currently believe that compliance with these laws will have a material adverse effect on our business.
Colorado
A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, in April 2019 the Colorado legislature subsequently enacted SB 181, which gave significant local control over oil and gas well head operations. Municipalities in Colorado have enacted local rules restricting oil and gas operations based on SB 181; nevertheless, in November 2020, a Colorado district court upheld the prior Colorado Supreme Court ruling in finding that a hydraulic fracking ban in the City of Longmont was preempted by state law. Additionally, in May 2024, the Colorado legislature enacted a bill that mandates a 50% reduction in nitrogen oxide emissions from upstream oil and gas operations by 2030, relative to 2017 levels. Oil and gas operators are required to obtain and maintain a license to conduct operations, in addition to necessary permits. The Colorado Energy and Carbon Management Commission (the “ECMC”) will enforce these requirements. The bill authorizes the ECMC to adopt rules requiring enhanced systems and practices to minimize emissions of ozone precursors at new oil and gas locations, particularly in areas designated as ozone nonattainment zones. The bill increases civil penalties for violations. It also allows for more stringent enforcement actions, including license suspension or revocation for severe violations. The bill also expands efforts to plug, reclaim, and remediate orphaned and marginal wells, with a focus on those at high risk of becoming orphaned, to mitigate environmental and public health risks. During the same legislative session, Colorado enacted a bill that imposes a “Production Fee for Clean Transit” and a “Production Fee for Wildlife and Land Remediation” on oil and gas produced in the state. Oil and gas producers are required to register and file returns detailing their production volumes and corresponding fees. Failure to comply with these requirements can result in penalties. In October 2024, the ECMC introduced rules to scrutinize the cumulative impacts of GHG emissions and set emissions intensity targets for operators. Local communities are considering additional restrictions, such as greater setbacks. The Colorado Department of Public Health and the Environment also set rules to curb methane emissions from pre-production activities. We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our operating partners and our revenue and results of operations.
Wyoming
On May 7, 2024, the Wyoming Department of Environmental Quality (“WDEQ”) issued an emergency rule in response to the EPA’s new air regulation 40 CFR Part 60 subpart OOOOb – “Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After December 6, 2022” (the “Methane Rule”). The Methane Rule establishes emission standards and compliance schedules for the control of GHGs. Subpart OOOOb requirements became federally effective on May 7, 2024, and as a result, oil and gas operators across the nation, including in Wyoming, must implement them. However, the EPA issued a direct
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interim final rule on July 31, 2025, and a final rule on December 3, 2025, that pushed the substantive deadlines in OOOOb and OOOOc back to January 2027. To assist Wyoming’s regulated community with implementing the EPA’s new requirements, WDEQ issued an Oil and Gas Emergency Rulemaking. Given EPA’s shortened timeframes and deadlines, the division initiated the emergency rulemaking process before initiating the regular rulemaking process. The regular rulemaking process will provide the public and stakeholders with the opportunity to comment and participate in the rulemaking process.
Human Capital Resources
As of December 31, 2025, we had 206 total employees, all of whom were full-time employees and all of whom were located in the United States. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.
We are focused on attracting, engaging, developing, retaining, and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with training and career development opportunities to enable employees to thrive and achieve their career goals. The health, safety, and well-being of our employees is of the utmost importance.
As part of our efforts to hire and retain highly qualified employees, we have structured compensation and benefits programs that, we believe, are extremely competitive and reward outstanding performance. In addition to the incentive programs in place for our named executive officers, which are described in detail under “Executive Compensation—Details of Our Compensation Program,” we have structured an incentive bonus program for non-officer employees that is dependent on an employee’s individual performance and our performance as a company. We also provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) contributions, medical-insurance options, and programs to encourage and support the employees’ development.
Our Offices
Our principal executive office is located in Irvine, California, and we have additional offices located in Dickinson and Williston, North Dakota; Denver, Colorado; Dallas, Texas; Fort Lauderdale, Florida; and Casper, Wyoming. We currently lease this office space and believe that the condition and size of our offices are adequate for our current needs, and that additional or alternative space will be available on commercially reasonable terms for future use and expansion.
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Item 1A. Risk Factors
Our business involves significant risks and uncertainties, some of which are described below. You should carefully consider the specific risks and uncertainties described below, together with the other information included in this Annual Report. If any of the risks discussed in this Annual Report occur, our business, prospects, liquidity, financial condition, and results of operations could be materially impaired, in which case the trading price of our Series A Preferred Shares may decline, we may be unable to pay the principal of, and interest on, our debt securities or make required distributions on our Series A Preferred Shares, and you could lose all or part of your investment. The risks and uncertainties described below are those that we have identified as material but are not the only risks and uncertainties we face. Our business is also subject to general risks and uncertainties that affect many other companies, including, but not limited to overall economic and industry conditions and additional risks not currently known to us or that we presently deem immaterial. Any of these risks or uncertainties may arise or become material and may negatively impact our business, prospects, liquidity, financial condition, and results of operations, or the trading price of our Series A Preferred Shares. Some statements in this Annual Report, including statements in the following risk factors, constitute forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements.”
The following is a summary of the principal risks that could adversely affect our business, operations, and financial results:
Risks Related to Our Business and Operations
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Risks Related to Legal, Regulatory, and Environmental Matters
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Risks Related to Our Indebtedness
Risks Related to Our Status as a Public Reporting Company
Risks Related to Our Business and Operations
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.
The key areas in which we face competition include:
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Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering, and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire, and develop reserves, and their ability to foster and maintain relationships with the relevant authorities.
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.
The mineral rights investment business involves high-risk activities with many uncertainties.
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:
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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.
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.
We, through the operations of PhoenixOp, face numerous risks relating to our drilling activities, including:
Risks we may face while completing our wells include, but are not limited to:
Further, many factors may occur that cause us to curtail, delay, or cancel scheduled drilling and completion projects, including, but not limited to:
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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.”
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.
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 under our indebtedness, including the Registered Notes, or the Series A Preferred Shares.
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.
We are in the business of both drilling and extracting oil and gas minerals directly through our operations conducted by PhoenixOp, and purchasing mineral rights and non-operated working interests in land in the United States, including the rights to drill for oil and gas. The prices we receive for our oil and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth, and carrying value of our properties. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand, as well as costs and terms of transport to downstream markets.
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 December 31, 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 our indebtedness, including the Registered Notes, and distributions on the Series A Preferred Shares.
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:
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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, including more recently due to the conflict in the Middle East and the closure of the Strait of Hormuz causing oil prices to increase significantly, such prices have historically remained volatile, and there can be no assurance that this price increase will be sustained and the volatility is expected to continue. This volatility 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 $66.01 per barrel and $3.387 per MMBtu, respectively, and our outlook for 2026 is based on average benchmark commodity prices of $63.90 per barrel for crude oil and $3.50 per MMBtu for natural gas, which are significantly higher than recent lows of $55.27 per barrel of for crude oil as of December 16, 2025 and $2.65 per MMBtu for natural gas as of October 17, 2025. Although prices have recently increased substantially after the onset of the conflict in the Middle East involving numerous oil producing countries and the closure of the Strait of Hormuz, there can no be assurance that prices will not experience another significant decrease. This plan and outlook may need
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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.
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 our indebtedness, including the Registered Notes, and distributions on the Series A 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.
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.
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.
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.
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 regarding interest rates and otherwise.
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 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.
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.
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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 operations and financial condition.
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.
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.
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.
We may encounter obstacles to marketing our minerals, which could adversely impact our revenues and profits.
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.
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.
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.
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.
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.
A significant portion of our consolidated revenue and accounts receivable 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 year ended December 31, 2025, three purchasers of our commodities made up 54.8% of our consolidated revenue, as compared to one purchaser of our commodities that made up 21.0% of our consolidated revenue for the year ended December 31, 2024. Similarly, as of December 31, 2025, we had concentrations in accounts receivable of 13.0% with one purchaser of our commodities. While we do not believe that the loss of any one
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purchaser, including such purchaser’s inability to pay already purchased commodities from us or continue their purchasing, would have a material impact on our revenue, to the extent there is a delay in payment from the purchaser or 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, or for that particular sale. 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 year ended December 31, 2025, twelve third-party E&P operators made up 14.7% of our consolidated revenue, as compared to ten third-party E&P operators that made up 35.3% of our consolidated revenue for the year ended December 31, 2024, and one third-party E&P operator that made up 11.0% of our consolidated revenue for the year ended December 31, 2023. Similarly, as of December 31, 2025, we had concentrations in accounts receivable of 13.0% 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, and 26.0% and 14.0% with two third-party E&P operators as of December 31, 2023. 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 into among the purchasers and such operators, and the operators, in turn, remit payment to the owners in accordance with their ownership percentage in each well (or unit of wells).
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 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.
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.
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 operations would be materially adversely affected.
With respect to our investments in which we have a non-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
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in drilling wells; selection of drilling technology; the availability of storage for hydrocarbons; and the rate of production of reserves, if any.
Furthermore, our E&P operators, including PhoenixOp, are dependent on various supplies and equipment, as well as qualified personnel, to carry out our extraction operations. Any shortage, unavailability, or increase in the cost of such supplies, personnel, equipment, and parts could have a material adverse effect on their ability to carry out operations and therefore limit or increase the cost of production and, ultimately, our profitability.
The challenges and risks faced by our third-party E&P operators and contractors may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments, and, if necessary, access additional capital. Commodity prices and/or other conditions have in the past caused, and may in the future cause, mineral operators to file for bankruptcy. The insolvency of third-party E&P operators or contractors of any of our properties, their failure to adequately perform, or their breach of applicable agreements could reduce our production and revenue or result in our liability to governmental authorities for compliance with environmental, safety, and other regulatory requirements or to such operators’ suppliers and vendors. Finally, with regards to any third-party E&P operator, they may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay its proportionate share of the defaulting party’s share of costs.
We rely on our third-party E&P operators, third parties, and government databases for information regarding our assets and, to the extent that information is incorrect, incomplete, or lost, our financial and operational information and projections may be incorrect.
As an owner of mineral and royalty interests, we rely on the third-party E&P operators of our properties to notify us and state regulators of information regarding production on our properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. We use this information in conjunction with our specialized software to evaluate operations and cash flows, as well as to predict expected production and possible future locations. To the extent we do not timely receive this information or the information is incomplete or incorrect, our financial and operational information may be incorrect and our ability to project potential growth may be materially adversely affected. Furthermore, to the extent we have to update any publicly disclosed results or projections made in reliance on this incorrect or incomplete information, investors could lose confidence in our reported financial information. If any of such third parties’ databases or systems were to fail for any reason, including as a result of a cyber-attack, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of the foregoing consequences could materially adversely affect our business.
Our estimated mineral reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate and they have not been verified by an independent third-party reserve engineering report. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulation of crude oil, natural gas, or NGL in an exact way. Numerous uncertainties are inherent in estimating quantities of mineral reserves. The process of estimating mineral reserves is complex, requiring significant expertise, decisions, and assumptions in the evaluation of available geological, engineering, and economic data for each reservoir, including assumptions regarding future natural gas and oil prices, subsurface characterization, production levels, and operating and development costs. For example, our estimates of our reserves are based on the unweighted first-day-of-the-month arithmetic average commodity prices over the prior 12 months in accordance with SEC guidelines. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of those estimates. Sustained lower prices will cause the 12-month unweighted arithmetic average of the first-day-of-the-month price for each of the 12 months preceding to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. To the extent that prices become depressed or decline materially from current levels, such conditions could render uneconomic a portion of our proved and probable reserves, and we may be required to write down our proved and probable reserves.
Additionally, we do not have an independent third-party reserve engineering report that verifies our estimates of mineral reserves quantities. We rely on our own internal team to estimate our mineral reserves, only employing third parties in limited capacities to assess the reasonableness and appropriateness of our approach and methodology
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to estimate our reserves. Lack of an independent third-party reserve engineering report means there is no independent complete analysis of the accuracy of mineral reserve estimates and their present value.
Furthermore, SEC rules require that, subject to limited exceptions, proved and probable undeveloped reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional proved and probable undeveloped reserves as we pursue our drilling program through PhoenixOp. To the extent that prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our proved and probable undeveloped reserves if we do not drill those wells within the required five-year time frame or choose not to develop those wells at all.
As a result, estimated quantities of reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to our reserves estimates. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of minerals attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery, and estimates of future net cash flows.
In addition, estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves, and the future cash flows related to such estimates, and should not be summed arithmetically with estimates of proved reserves and the future cash flows related to such estimates. When producing an estimate of the amount of minerals that are recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration, and development, price changes, and other factors. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Recovery of proved and probable undeveloped reserves requires significant capital expenditures and successful drilling operations. As of December 31, 2025, approximately 54.6% of our total estimated proved reserves and 100.0% of our total estimated probable reserves were undeveloped. Furthermore, as of December 31, 2025, we had 228.0 million Boe in total estimated probable undeveloped reserves, which is approximately 2.0 times our total proved reserves. Our reserves estimates assume that substantial capital expenditures will be made to develop non-producing reserves. As of December 31, 2025, we estimate that we will need to make approximately $1,064.1 million and $2,167.3 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively. Estimates of capital expenditures are subject to fluctuations in oil and natural gas prices, equipment availability, labor markets, and other factors that we may not foresee or control. As such, we cannot be sure that the estimated costs attributable to our reserves are accurate.
We anticipate that over the next several years our cash flows from operations alone will not be sufficient to finance the development of our estimated proved and probable undeveloped reserves over that period. As a result, we expect that we will need to raise additional capital to develop our reserves. However, we cannot be certain that additional financing will be available to us on acceptable terms, or at all. See “—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 regarding interest rates and otherwise.” Additionally, sustained or further declines in commodity prices may require use to revise the future net revenues of our estimated proved and probable undeveloped reserves and may result in some projects becoming
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uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserves estimates, which could have a material adverse effect on our financial condition, future cash flows, and results of operations.
The ability to develop our reserves is subject to a number of uncertainties, which could defer our drilling more than five years from the date undeveloped reserves were first assigned to a drilling location. Alternatively, our estimated reserves may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, because undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any undeveloped reserves that are not developed within this five-year time frame or to reclassify the category of the applicable reserves. A removal or reclassification of reserves could reduce the quantity and present value of our natural gas and oil reserves, which would adversely affect our business and financial condition.
We may experience delays in the payment of royalties and be unable to replace third-party E&P operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of such third-party E&P operators on those leases declare bankruptcy.
We may experience delays in receiving royalty payments from our third-party E&P operators, including as a result of delayed division orders received by our third-party E&P operators. A failure on the part of our third-party E&P operators to make royalty payments typically gives us the right to terminate the lease, repossess the property, and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement E&P operator. However, we might not be able to find a replacement E&P operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing third-party E&P operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt third-party E&P operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another E&P operator. For example, certain of our third-party E&P operators historically have undergone restructurings under the Bankruptcy Code and any future restructurings of our third-party E&P operators may impact their future operations and ability to make royalty payments to us. If the third-party E&P operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new E&P operator, the replacement E&P operator may not achieve the same levels of production or sell oil or natural gas at the same price as the third-party E&P operator we replaced.
Our PV-10 will not necessarily be the same as the current market value of our estimated proved reserves.
You should not assume that our PV-10 is the current market value of our estimated proved reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our reserves will be affected by factors such as:
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing and amount of actual future net revenues from proved reserves and, thus, their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks
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associated with our business or the natural gas and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.
Estimated reserves do not represent or measure the fair value of the respective property or asset and we may sell or divest an asset for much less than the amount of estimated reserves.
Estimated proved reserves and estimated probable reserves do not represent or measure the fair value of the respective properties or the fair market value at which a property or properties could be sold. In the event of any such sale, proceeds to us may be significantly less than the value of the estimated reserves. The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves and the future cash flows related to such estimates but have not been adjusted for risk due to such uncertainty.
Our future success depends on our ability to replace reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost. We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive, or that we will recover all or any portion of our investments in our properties and reserves.
We rely on our software system to identify attractive assets with oil and gas reserves and there can be no assurance that we will be able to continue to scale this software or that such software will be accurate in identifying assets.
As of the date of this Annual Report, we have built and operated our software system on a relatively limited scale. While we believe that our development and testing to date has proven the concept of our software, there can be no assurance that, as we commence larger-scale operations, we will not incur unexpected costs or hurdles that might restrict the desired scale of our intended operations or negatively impact our business prospects, financial condition, and results of operations. In addition, due to the limited and changing scale of use, there can be no assurance that the software will be accurate on an ongoing or continuous basis. If our software is unable to scale or to adopt to the changing nature of our operations, or is inaccurate, our ability to successfully invest in commercially viable mineral deposits and PhoenixOp’s ability to successfully extract minerals from assets transferred to it by us could be significantly impacted and our business and operating results may suffer.
We may be unable to realize all of the anticipated benefits from our acquisitions or successfully integrate future acquisitions of mineral rights into our business.
Our ability to achieve the anticipated benefits of our completed and future acquisitions of mineral rights will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:
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The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, in conjunction with the use of our specialized software, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. Even if we identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We depend on acquisitions to grow our reserves, production, and cash flows.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain the necessary financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen difficulties. In addition, if we acquire interests in new geographic regions, we may be subject to additional and unfamiliar legal and regulatory requirements. Moreover, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties, including delays, and may require a disproportionate amount of our managerial and financial resources.
No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Our failure to successfully integrate the acquired assets into our existing operations, achieve cost savings, or minimize any unforeseen difficulties could materially and adversely affect our financial condition, results of operations, and cash flows. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash flows.
Our E&P operators’ identified potential drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Proved and probable undeveloped drilling locations represent a significant part of our growth strategy. However, we do not fully control the development of these locations that we do not directly operate. The ability of our E&P operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, the generation of additional seismic or geological information, seasonal conditions and inclement weather, regulatory changes and approvals, oil and gas prices, costs, negotiation of agreements with third parties, drilling results, lease expirations, and the availability of water. Further, our E&P operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our E&P operators, or us, to know conclusively prior to drilling whether mineral reserves will be present or, if present, whether such resources will be present in sufficient quantities to be economically viable. Even if sufficient amounts of such resources exist, our E&P operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our E&P operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business and ours.
There is no guarantee that the conclusions our E&P operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other E&P operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells may be less than expected. For example, several third-party E&P operators have previously announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, we do not know if the potential drilling locations identified will ever be drilled or if our third-party E&P operators will be able to produce oil and/or gas from these or any other potential drilling locations. As such, the actual drilling
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activities of our E&P operators may materially differ from those presently identified, which could adversely affect our business, results of operations, and cash flows.
Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data through our specialized software. As a result, our third-party E&P operators may have reached different conclusions about the potential drilling locations on our properties, and our third-party E&P operators control the ultimate decision as to where and when a well is drilled.
Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our E&P operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities.
Leases on crude oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.
Any reduction in our E&P operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or terminates, all mineral rights revert back to us, and we will have to seek new lessees to explore and develop such mineral interests.
We have limited control over the activities on properties that we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety, and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party E&P operator could decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of decreases in oil and gas prices. These limitations and our dependence on the third-party E&P operators and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production, and materially and adversely affect our financial condition, results of operations, and cash flows.
We have completed numerous acquisitions of mineral and royalty interests for which separate financial information is not required or provided.
We have completed numerous acquisitions of mineral and royalty interests that are not “significant” under Rule 3-05 of Regulation S-X (“Rule 3-05”). Therefore, we are not required to, and have elected not to, provide separate historical financial information in our public filings relating to those acquisitions. While these acquisitions are not individually or collectively significant for purposes of Rule 3-05, they have or will have an impact on our financial results and their aggregated effect on our business and results of operations may be material.
The substantial majority of the wells in which we have a mineral or royalty interest and all the wells we directly operate are located in the Williston Basin, making us vulnerable to risks associated with concentration of our assets in a limited geographic area.
The substantial majority of the wells in which we have a mineral or royalty interest and all the wells we directly operate are geographically concentrated in the Williston Basin. As a result, we may be disproportionately exposed to various factors, including, among others:
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This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the region, such as natural disasters, seismic events, industrial accidents, or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs, and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Cybersecurity attacks on our technological systems, or those of our third-party vendors, could significantly disrupt our business operations and subject us to liability.
Our business, like other companies in the oil and gas industry, has become increasingly dependent upon digital technologies. We utilize digital technologies to, among other things, process and record financial and operating data, communicate with our business partners, analyze mineral deposits information, and estimate quantities of mineral reserves. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability.
There is no guarantee that our security measures will provide absolute security. We may not be able to anticipate, detect, or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using techniques designed to circumvent controls and avoid detection. We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in the unauthorized access to our information systems or data, the data of our third-party E&P operators, and our employees, or significant disruption to our business. These attacks could adversely impact our business operations, our revenue and profits, our ability to comply with legal, contractual, and regulatory requirements, our reputation and goodwill, and could result in legal risk, enforcement actions, and litigation. As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to investigate and remediate any information systems and related infrastructure security vulnerabilities. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could require us to expend significant additional resources to meet such requirements.
Security incidents can also occur as a result of non-technical issues, such as physical theft. More recently, advancements in artificial intelligence (“AI”) may pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition, or screening questions to confirm identities. In addition, generative AI systems may also be used by malicious actors to create more sophisticated cyberattacks (i.e., more realistic phishing or other attacks). The advancements in AI could lead to an increase in the frequency of identity fraud or cyberattacks (whether successful or unsuccessful), which could cause us or our third-party E&P operators to incur increasing costs, including costs associated with additional personnel, protection technologies and policies and procedures, and third-party experts and consultants. If any of these security breaches were to occur, we could suffer disruptions to our operations and other aspects of our business.
Our inability to retain or obtain key personnel could directly affect our efficiency and profitability.
Our future success depends on retaining the services of our planned management team. Our executive officers possess a unique and comprehensive knowledge of our industry and related matters that are vital to our success within the industry. The knowledge, leadership, and technical expertise of these individuals would be difficult to replace. The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long-term business strategy.
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We may incur losses as a result of title defects in the properties that we acquire.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit, or in any other mineral interest may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
If the third-party E&P operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations, and cash flows may be adversely affected.
We depend in part on acquisitions to grow our reserves, production, and cash generated from operations. In connection with these acquisitions, record title to mineral and royalty interests are conveyed to us by asset assignment, and we become the record owner of these interests. Upon such a change in ownership of mineral interests, and at regular intervals pursuant to routine audit procedures at each of our third-party E&P operators at its discretion, the third-party E&P operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the third-party E&P operator may suspend payment of the related royalty. If a third-party E&P operator of our properties is not satisfied with the documentation we provide to validate our ownership, such third-party E&P operator may suspend our royalty or mineral interest right payment until such issues are resolved, at which time we would receive in full payments that would have been made during the suspension, without interest. Certain of our third-party E&P operators impose significant documentation requirements for title transfer and may suspend royalty payments for significant periods of time. During the time that a third-party E&P operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. Placement of a significant amount of our royalty interests in suspense may have a material advance effect on our business and results of operations.
Our decommissioning costs are unknown and may be substantial and may force us to divert resources from our other operations.
We may become responsible for costs associated with abandoning and reclaiming wells, facilities, and pipelines (“decommissioning costs”) we use for production of oil, natural gas, and NGL reserves. We accrue a liability for decommissioning costs associated with our wells but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
Limitation or restrictions on our ability to obtain water for our direct drilling and hydraulic fracturing processes may have an adverse effect on our operating results.
Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas, or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. In addition, the use, treatment, and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs, or other adverse effects on our business, results of operations, and financial condition. The inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact operations of our E&P operators and have a corresponding adverse effect on our business, results of operations, and financial condition.
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Weather conditions, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion, and production activities in the areas where we operate.
Exploration and development activities and equipment of PhoenixOp and our third-party operators operating on our lands can be adversely affected by severe weather, such as well freeze-offs, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our and our third-party operators’ planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. In addition, demand for oil and gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. These constraints could delay or temporarily halt our operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Our hedging activities could result in financial losses and reduce earnings.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars, and basis swaps. We have not designated and do not plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:
In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.
Risks Related to Legal, Regulatory, and Environmental Matters
We are subject to significant governmental regulations, and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, which could restrict our operations, increase costs of conducting our business, and delay our implementation of, or cause us to change, our business strategy.
The current and future operations of our business and that of the third-party E&P operators on our land are and will be governed by complex and stringent federal, state, local, and other laws and regulations, including:
Federal, state, and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Companies engaged in exploration activities often experience increased costs and delays in production and other schedules as a result of the need to comply with applicable laws, regulations, and permits. Costs of compliance may
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increase, and operational delays or restrictions may occur, as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations. Government authorities and other organizations continue to study health, safety, and environmental aspects of mineral operations, including those related to air, soil, and water quality, ground movement or seismicity, and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting, well construction, and public disclosure or environmental review of, or restrictions on, mineral operations. Such requirements or associated litigation could result in potentially significant added costs to comply, delay, or curtail our exploration, development, disposal, or production activities, and preclude us from carrying out our exploration program, which could have a material adverse effect on our expected production, other operations, and financial condition.
To operate in compliance with these laws and regulations, we and our third-party E&P operators must obtain and maintain permits, approvals, and certificates from federal, state, and local government authorities for a variety of activities. These permits are generally subject to protest, appeal, or litigation, which could in certain cases delay or halt projects, production of wells, and other operations. Failure to comply with laws and regulations, including obtaining and maintaining permits, approvals, and certificates, may result in enforcement actions, including the forfeiture of claims, or orders issued by regulatory or judicial authorities requiring operations to cease or be curtailed, the assessment of administrative, civil, and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, including capital expenditures, installation of additional equipment, or remedial actions, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations.
Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies, and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
The development and enactment of climate change legislation and regulation regarding emissions of GHGs could adversely affect our operations, including the mineral industry and the demand for the oil and natural gas that we produce.
The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state, and local statutes, rules, orders, and regulations that may, in turn, adversely affect the operations and costs of the companies engaged in the energy industry. Laws, regulations, and existing policies related to climate change and to GHG emissions have been rapidly evolving and are increasingly difficult to predict, particularly in light of recent announcements and actions by the U.S. government to reconsider air-related regulations and policies.
For instance, in response to the EPA’s endangerment finding on GHGs, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on our properties. However, on June 11, 2025, the EPA proposed a rule to repeal all GHG emissions standards for the power sector under the CAA and to repeal amendments to the 2024 Mercury and Air Toxics Standards. On February 12, 2026, the EPA issued a fine rule to rescind the 2009 GHG endangerment finding and, on February 24, 2026, the EPA issued a rule to repeal certain amendments to the 2024 Mercury and Air Toxics Standards. The final February 12, 2026 rule is subject to litigation and we cannot predict the outcome of such litigation or any potential impacts at this time.
Further, the IRA 2022 includes billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure, and carbon capture and sequestration. Additionally, the IRA 2022 includes a charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and although the IRA 2022 generally provides for a conditional exemption under certain circumstances, the change applies to emissions that exceed an established emissions threshold for each type of covered facility. On November 12, 2024, the EPA finalized the methane emissions charge rule, implementing the IRA 2022. To the extent the methane emissions charge rule is implemented as originally promulgated, it could increase the operating costs of our E&P operators and adversely
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affect our business. On March 14, 2025, the U.S. Congress signed legislation disapproving this rule and, therefore, the future of this rule remains unclear.
Additional GHG regulation could also result from the Paris Agreement. Under the Paris Agreement, the United States committed to reducing its GHG emissions by 26-28% by the year 2025 as compared with 2005 levels; however, in January 2025, President Trump issued an executive order directing the United States to withdraw from the Paris Agreement and, on January 27, 2026, the United States officially withdrew from the Paris Agreement. As a result, the effect of the Paris Agreement on our business is uncertain. Moreover, in November 2021, at the UNFCCC 26th COP, the United States and the European Union advanced a Global Methane Pledge to reduce global methane emissions at least 30% from 2020 levels by 2030, which over 100 countries have signed. In November 2025, Brazil hosted the 30th COP, with no official participation by or representatives from the United States. While Congress has from time to time considered legislation to reduce emissions of GHGs, comprehensive legislation aimed at reducing GHG emissions has not yet been adopted at the federal level.
New or existing laws and regulations relating to climate change, including state cap-and-trade programs, may affect our business operations through imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from our properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets.
Our business and results of operations are subject to physical risks associated with climate change.
Changes in climate have caused, and are expected to continue to cause, among other things, increasing mean annual temperatures, rising sea levels, and changes to meteorological and hydrological patterns, as well as impacts to the frequency and intensity of wildfires, freezes, floods, drought, hurricanes, other storms, and severe weather-related events and natural disasters. These changes have and could continue to significantly impact our future results of operations and may have a material adverse effect on our business, financial condition, and results of operations. Accordingly, a natural disaster has the potential to disrupt our and our third-party E&P operators’ businesses and may cause us to experience work stoppages, project delays, financial losses, and additional costs to resume operations, including increased insurance costs or loss of coverage, legal liability, and reputational losses, and we expect that increasing physical climate-related impacts may result in further changes to the cost or availability of insurance in the future.
Our and our third-party E&P operators are subject to complex federal, state, and other environmental, health, and safety laws and regulations that could adversely affect the cost, manner, or feasibility of conducting our operations or expose us and our third-party E&P operators to significant liabilities.
Our operations, through PhoenixOp and our third-party E&P operators, are subject to a complex and rapidly evolving set of federal, state, local, and international environmental, health, and safety laws and regulations. These laws govern the generation, use, storage, release, management, and disposal of, or exposure to, hazardous materials and wastes, the remediation of contaminated sites, fuel storage, wastewater and stormwater discharges, air emissions, the protection of natural resources (such as protected wetlands or threatened and endangered species and their habitat), and occupational health and safety. These laws, rules, and regulations may require us to obtain and maintain regulatory licenses, permits, and other approvals, comply with the requirements of such licenses, permits, and other approvals, and perform environmental impact studies prior to commencing new projects or making changes to existing projects.
We, through PhoenixOp and our third-party E&P operators, perform work involving hazards and operating risks associated with drilling for and production of crude oil, natural gas, and NGL, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of crude oil, natural gas, NGL, and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and environmental hazards, such as crude oil and NGL spills, natural gas leaks and ruptures, or discharges of toxic gases.
In addition, their operations are subject to risks associated with hydraulic fracturing. These risks include any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us or our third-party E&P operators due to
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injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and repairs required to resume operations, which in turn could have a material adverse effect on our financial condition, results of operations, and cash flows.
The exploration and possible future development phases of our business and the business of our third-party E&P operators are and will be subject to federal, state, and local environmental regulation. These regulations mandate, among other things, the maintenance of air and water quality standards and land reclamation. They also set out limitations on the generation, transportation, storage, and disposal of solid and hazardous waste. New environmental legislation may impose stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental regulatory scrutiny, and a heightened degree of responsibility for companies and their officers, directors, and employees. Potential changes in environmental regulations, if any, may adversely affect our operations and the operations of the third-party E&P operators on our land. If we fail to comply with any of the applicable environmental laws, regulations, or permit requirements, we could face regulatory or judicial sanctions. Penalties imposed by either the courts or administrative bodies could delay or stop our operations or the operations of the third-party E&P operators on our land or require considerable capital expenditures. Furthermore, certain groups opposed to exploration and mining may attempt to interfere with our operations through the legal or regulatory process or by engaging in disruptive protest activities.
Unknown environmental hazards, potentially caused by previous or existing owners or operators, may exist on properties in which we hold an interest. Our properties could be located on or near an ongoing environmental cleanup site, which may result in unexpected liabilities, with total costs that are difficult to predict.
CERCLA and comparable state statutes impose strict joint and several liability on current and former owners and operators of sites and on persons who disposed of or arranged for the disposal of hazardous substances found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. RCRA and comparable state statutes govern the disposal of solid waste and hazardous waste and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. CERCLA, RCRA, and comparable state statutes can impose liability for clean-up costs of sites and disposal of substances found on exploration, mining, and processing sites long after activities on such sites have been completed.
The CAA restricts the emission of air pollutants from many sources, including mining and processing activities. The mining operations conducted by third parties on our land may produce air emissions, including fugitive dust and other air pollutants from stationary equipment, storage facilities, and the use of mobile sources such as trucks and heavy construction equipment, which are subject to review, monitoring, and/or control requirements under the CAA and state air quality laws. In undeveloped properties, third-party operators may be required to obtain permits before work can begin, and, in properties with existing facilities, our operators may need to incur capital costs in order to remain in compliance. In addition, permitting rules may impose limitations on their production levels or result in additional capital expenditures to comply with the rules.
The National Environmental Policy Act requires federal agencies to integrate environmental considerations into their decision-making processes by evaluating the environmental impacts of their proposed actions, including issuance of permits to mining facilities, and assessing alternatives to those actions. If a proposed action could significantly affect the environment, the agency must prepare a detailed statement known as an EIS. The EPA, other federal agencies, and any interested third parties will review and comment on the scoping of the EIS and the adequacy of and findings set forth in the draft and final EIS. This process can cause delays in issuance of required permits or result in changes to a project to mitigate its potential environmental impacts, which can in turn adversely impact the economic feasibility of a proposed project.
The CWA and comparable state statutes impose restrictions and controls on the discharge of pollutants into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA regulates storm water mining facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal, and administrative
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penalties for unauthorized discharges of pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.
The SDWA and the Underground Injection Control (the “UIC”) program promulgated thereunder regulate the drilling and operation of subsurface injection wells. The EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal or injection well. Violation of these regulations and/or contamination of groundwater by mining-related activities may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by neighboring landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
There can be no assurance that our defense of such claims will be successful. A successful claim against us or any of the third parties we contract with could have an adverse effect on our business prospects, financial condition, and results of operations.
We or our third-party E&P operators could be subject to environmental lawsuits.
The oil and natural gas industry involves various operational hazards and risks, such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, spills, pollution, releases of toxic gas, and other environmental threats. These hazards could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. In addition, we may be held liable for environmental damages caused by previous owners or operators of property we have acquired. Environmental hazards and damages may extend beyond our land, prompting neighboring landowners and other third parties to file claims under environmental statutes and common law for personal injury and property damage allegedly resulting from the release of hazardous substances or other waste material into the environment on or near our properties. There can be no guarantee that our defense of such claims will be successful. A successful claim against us or any of the third parties we contract with to conduct operations on our land could have an adverse effect on our business prospects, financial condition, and results of operations.
We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology.
As of the date of this Annual Report, we do not own any registered intellectual property rights for our software system used in our mineral rights discovery, grading and estimates, and acquisition. We rely in part on proprietary tools and data workflows to support our acquisition evaluation process; however, we do not believe our business is dependent on any single software application. We use internally developed tools, third-party data sources, and proprietary processes to support our mineral and royalty acquisition efforts. While we consider these tools to be helpful, our competitive position is also driven by other factors, including our experience, relationships, access to capital, underwriting discipline, and operational execution. Although we take measures designed to protect our proprietary tools and information, including confidentiality agreements, access controls, and other security measures, there can be no assurance that these measures will prevent unauthorized access or misuse. If a third party were to obtain access to certain proprietary information or tools, we could incur additional costs to enhance our systems, face claims or litigation, or experience business disruptions. Any such events could adversely affect our operations; however, we do not expect that unauthorized access to our software alone would materially impair our ability to execute our business strategy.
Third parties may initiate legal proceedings alleging that our use of our software system is infringing or otherwise violating their intellectual property rights, which could lead to costly disputes or disruptions.
Our commercial success depends in part on our ability to continue to develop and use our proprietary mineral exploration software system without infringing the intellectual property or proprietary rights of third parties. However, from time to time, we may be subject to legal proceedings and claims in the ordinary course of business with respect to intellectual property. Intellectual property disputes can be costly to defend and may cause our business, operating results, and financial condition to suffer. As the applied science industry and investments in mineral rights in the United States expand, the risk increases that there may be patents issued to third parties that relate to our software of which we are not aware or that we must challenge to continue our operations as currently contemplated. Whether
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merited or not, we may face allegations that we or parties indemnified by us have infringed or otherwise violated the patents, trademarks, copyrights, or other intellectual property rights of third parties. Such claims may be made by competitors seeking to obtain a competitive advantage or by other parties. We may also face allegations that our employees have misappropriated the intellectual property or proprietary rights of their former employers or other third parties.
It may be necessary for us to initiate litigation to defend ourselves in order to determine the scope, enforceability, and validity of third-party intellectual property or proprietary rights, or to establish our respective rights. Regardless of whether claims that we are infringing patents or other intellectual property rights have merit, such claims can be time-consuming, can divert management’s attention and financial resources, and can be costly to evaluate and defend. Results of any such litigation are difficult to predict and may require us to stop commercializing or using our products or technology, obtain licenses, modify our solutions and technology while we develop non-infringing substitutes, incur substantial damages or settlement costs, or face a temporary or permanent injunction prohibiting us from marketing or providing the affected products and solutions. If we require a third-party license, it may not be available on reasonable terms or at all, and we may have to pay substantial royalties or upfront fees or grant cross-licenses to intellectual property rights for the use of our software. We may also have to redesign our software so it does not infringe third-party intellectual property rights, which may not be possible or may require substantial monetary expenditures and time, during which our technology may not be available for use. Even if we have an agreement to indemnify us against such costs, the indemnifying party may be unable to uphold its contractual obligations. If we cannot or do not obtain a third-party license to the infringed technology, license the technology on reasonable terms, or obtain similar technology from another source, our operations could be adversely impacted.
Further, some third parties may be able to sustain the costs of complex litigation more effectively than we can because they have substantially greater resources. Even if resolved in our favor, litigation or other legal proceedings relating to intellectual property claims may cause us to incur significant expenses and could distract our technical and management personnel from their normal responsibilities. In addition, there could be public announcements of the results of hearings, motions, or other interim proceedings or developments, and if securities analysts or investors perceive these results to be negative, it could have a material adverse effect on our business. Moreover, any uncertainties resulting from the initiation and continuation of any legal proceedings could have a material adverse effect on our ability to raise the funds necessary to continue our operations. Assertions by third parties that we violate their intellectual property rights could therefore have a material adverse effect on our business, financial condition, and results of operations.
We could be subject to changes in our tax rates, the adoption of new tax legislation, or exposure to additional tax liabilities.
Current economic and political conditions make tax rates in any jurisdiction subject to significant change. Our future effective tax rates could also be affected by changes in the valuation of our deferred tax assets and liabilities, or changes in tax laws or their interpretation, including changes in tax laws affecting our products and solutions and the oil and gas industry more generally. We are also subject to the examination of our tax returns and other documentation by the IRS and state tax authorities. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations or that our assessments of the likelihood of an adverse outcome will be correct. If our effective tax rates were to increase or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, this could materially and adversely impact our financial condition and results of operations.
Current and future litigation, regulatory, administrative, or other legal proceedings could have a material adverse effect on our business and results of operations.
Lawsuits and regulatory, administrative, or other legal proceedings that have arisen or may arise, including, but not limited to, in connection with our oil and gas operations and the financing thereof, can involve substantial costs, including the costs associated with investigation, litigation, and possible settlement, judgment, penalty, or fine. In addition, such matters may be time-consuming to defend or prosecute and may require a commitment of management and personnel resources that will be diverted from our normal business operations. There can be no assurance that costs associated with such matters will not exceed the limits of any applicable insurance policies that we may have. Moreover, we may be unable to continue to maintain any insurance at a reasonable cost, if at all, or to secure additional coverage, which may result in costs being uninsured. Our business, financial condition, and results of operations could
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be adversely affected if a matter is adversely determined and, irrespective of a final determination, any such matter could significantly impact our reputation and ability to conduct our business.
Risks Related to Our Indebtedness
Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness, including the Registered Notes, and the Series A Preferred Shares.
We have a significant amount of indebtedness. We may not generate sufficient cash flow from operations, or have future borrowings available under credit facilities or other sources of financing, to enable us to repay our indebtedness, including the Registered Notes, to make distributions on the Series A Preferred Shares, or to fund our other liquidity needs. As of December 31, 2025, after giving effect to the borrowing of an additional $75.0 million under the Fortress Credit Agreement in February 2026, we had approximately $1,604.9 million of indebtedness outstanding, which comprised $525.0 million outstanding under the Fortress Credit Agreement, $253.3 million outstanding under the Adamantium Loan Agreement (and corresponding amount of Adamantium Securities), $710.7 million of Reg D Bonds outstanding, $50.2 million of Reg A Bonds outstanding, $31.0 million of Exchange Notes outstanding, and $34.7 million of Registered Notes outstanding. Furthermore, the Fortress Credit Agreement provides for a $15.0 million tranche of loans that represent a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Credit Agreement or a bankruptcy filing by the Credit Parties. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.”
Specifically, our high level of indebtedness could have important consequences to our business and to holders of our securities, including:
Any such consequences could have a material adverse effect on our business, results of operations, and financial condition.
Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above.
We may incur significant additional indebtedness in the future. The indentures governing our debt securities do not contain any limitations on our ability to incur additional indebtedness, including Senior Debt or debt that matures or is redeemable prior to the stated maturity of our existing debt. Although the Fortress Credit Agreement contains,
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and the terms of future indebtedness we incur may contain, restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the additional indebtedness incurred in compliance with these restrictions could be substantial. In each case, this could reduce the amount of proceeds paid to you. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness. If new indebtedness or other obligations are added to our current indebtedness levels, the related risks that we now face would increase.
We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Registered Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
As a result of our substantial indebtedness, a significant amount of our cash flow will be required to pay interest and principal on our outstanding indebtedness. Our ability to make scheduled payments on or refinance our indebtedness, including the Registered Notes, or to make distributions on the Series A Preferred Shares depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and to certain financial, business, legislative, regulatory, and other factors beyond our control. We may be unable to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal of, premium, if any, and interest on our indebtedness, including the Registered Notes, to make distributions on the Series A Preferred Shares, or to service our other obligations.
We recorded net income (loss) of $66.1 million, $(24.8) million, and $(16.2) million for the years ended December 31, 2025, 2024, and 2023, respectively. Through 2025, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt and cash distributions on our preferred equity in 2025. Furthermore, as of December 31, 2025, we estimate that we will need to make approximately $1,064.1 million and $2,167.3 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we would need to raise approximately $669.8 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service our cash interest and principal payment obligations under our existing debt arrangements for the foreseeable future, our current development plan contemplates capital expenditures in excess of operating cash flow in certain periods. Accordingly, we intend to fund a portion of our growth capital through a combination of operating cash flow, available borrowing capacity, and capital markets transactions, consistent with our historical practice. We regularly evaluate our capital structure and liquidity profile to maintain appropriate financial flexibility while executing our development plan. We may from time to time refinance, extend, or restructure portions of our indebtedness through capital markets transactions or private financing arrangements in order to optimize maturities and cost of capital. See “—Risks Related to Our Business and Operations—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 regarding interest rates and otherwise,” “—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
If our cash flows from operations and capital resources are insufficient to fund our debt service obligations or make distributions on our preferred equity, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital, or restructure or refinance our indebtedness, including the Registered Notes. We may not be able to effect any such alternative measures on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to meet our scheduled debt service obligations. If we cannot make scheduled payments on our indebtedness, we will be in default and holders of such indebtedness could declare all outstanding principal of, premium on, and interest, if any, on such indebtedness to be due and payable, and the lenders under any revolving or delayed draw credit facilities could terminate their commitments to loan money to us. As a result of a default, any secured lenders, including Fortress, could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. All of these events could result in your losing all or a part of your investment in the Registered Notes or Series A Preferred Shares, as applicable.
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Furthermore, the Fortress Credit Agreement restricts, and our future indebtedness may restrict, our ability to dispose of assets and use the proceeds from such dispositions and may also restrict our ability to raise debt or equity capital to be used to repay other indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to meet any debt service or other obligations then due.
We will need to repay or refinance a substantial amount of our indebtedness. Failure to do so could have a material adverse effect on our business, results of operations, and financial condition.
As of December 31, 2025, after giving effect to the borrowing of an additional $75.0 million in aggregate under the Fortress Credit Agreement in February 2026, we had approximately $823.2 million of indebtedness maturing within three years, including all amounts under the Fortress Credit Agreement, $987.3 million of indebtedness maturing within five years, $1,109.1 million of indebtedness maturing within seven years, and $1,604.9 million of indebtedness maturing within eleven years. Furthermore, the Fortress Credit Agreement provides for a $15.0 million tranche of loans, which represent a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Credit Agreement or a bankruptcy filing by the Credit Parties. The terms of our debt securities contain mandatory redemption provisions providing the holders thereof with the ability to request redemption of their securities at any time prior to maturity at a price equal to 100% (with respect to the Adamantium Secured Note), 90% (with respect to the Senior Reg D Bonds), or 95% (with respect to the Adamantium Bonds, the Reg A Bonds, the Subordinated Reg D Bonds, the Exchange Notes, and the Registered Notes) of the principal amount being redeemed. The amount of such redemption is limited (i) on an annual basis to 10% of the aggregate principal amount of Registered Notes, Adamantium Bonds, Reg A Bonds, or Subordinated Reg D Bonds, as applicable, then issued and outstanding, and (ii) $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.” Consequently, we will need to repay, refinance, replace, or otherwise extend the maturity of a substantial amount of our existing indebtedness. Our ability to repay, refinance, replace, or extend will be dependent on, among other things, business conditions, our financial performance, and the general condition of the financial markets. If a financial disruption were to occur at the time that we are required to repay such indebtedness, we could be forced to undertake alternate financings, negotiate for an extension of the maturity of such indebtedness, or sell assets and delay capital expenditures in order to generate proceeds that could be used to repay such indebtedness. We cannot assure you that we will be able to consummate any such transaction on terms that are commercially reasonable, on terms acceptable to us, or at all. Our failure to repay, refinance, replace, or otherwise extend the maturity of our indebtedness could result in an event of default under the documents governing our indebtedness, which could lead to an acceleration or repayment of substantially all of our outstanding indebtedness. All of these events could result in your losing all or a part of your investment in the Registered Notes or Series A Preferred Shares, as applicable.
The terms of our outstanding indebtedness restrict, and the terms of future indebtedness we may incur may restrict, our current and future operations, particularly our ability to respond to changes in the economy or our industry or to take certain actions, which could harm our long-term interests.
The agreements governing certain of our existing indebtedness contain, and the agreements governing future indebtedness we may incur may contain, a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:
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In addition, the Fortress Credit Agreement contains financial covenants that require us to maintain (a) a maximum total secured leverage ratio (i) as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024), (ii) as of the last day of any fiscal quarter during the period from March 31, 2026 through September 30, 2026 of less than or equal to 1.85 to 1.00, and (iii) as of the last day of any fiscal quarter ending on or after December 31, 2026 of less than 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through March 31, 2026, (iii) 0.90 to 1.00 from April 30, 2026 through December 31, 2026, and (iv) 1.00 to 1.00 for each calendar month ending thereafter, and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter (i) ending during the period from June 30, 2024 through December 31, 2024 of at least 2.00 to 1.00, (ii) ending during the period from March 31, 2025 through December 31, 2025 of at least 1.70 to 1.00, (iii) ending during the period from March 31, 2026 through June 30, 2026 of at least 1.50 to 1.00, (iv) ending during the period from September 30, 2026 through December 31, 2026 of at least 1.70 to 1.00, and (v) ending during the period from March 31, 2027 and thereafter of at least 2.00 to 1.00. Our ability to meet the financial covenant could be affected by events beyond our control.
Furthermore, subject to certain conditions, the Reg A Bonds require that we offer to purchase all or any amount of the outstanding Reg A Bonds at a price equal to the then-outstanding principal on the Reg A Bonds being repurchased, plus any accrued but unpaid interest on such Reg A Bonds, upon a change of control.
These restrictions may affect our ability to service our indebtedness or grow in accordance with our strategy. As a result of all of these restrictions, we may be:
A breach of the covenants under any such indebtedness could result in a default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related indebtedness and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, an event of default under any revolving or delayed draw credit facilities would permit the lenders under those facilities to terminate all commitments to extend further credit thereunder.
Furthermore, if we were unable to repay the amounts due and payable under any secured indebtedness, including the Fortress Credit Agreement, those lenders could proceed against the collateral granted to them, including our available cash, to secure that indebtedness, subject to the provisions of any outstanding intercreditor arrangements. In the event our lenders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness. All of these events could result in your losing all or a part of your investment in the Registered Notes or Series A Preferred Shares, as applicable.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under the Fortress Credit Agreement are, and borrowings under indebtedness we may incur in the future may be, at variable rates of interest and expose us to interest rate risk. If interest rates were to increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, including the Registered Notes, and making distributions on the Series A Preferred Shares will correspondingly decrease. In the future, we may enter into interest rate swaps that involve the exchange of floating-for fixed-rate interest payments in order to reduce interest rate volatility or risk. However, we may not maintain interest rate swaps with respect to any of our variable rate indebtedness, and any swaps we enter into may not fully or effectively mitigate our interest rate risk.
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We have in the past failed, and may in the future fail, to satisfy one or more of the financial covenants under the Fortress Credit Agreement. While we have historically been able to negotiate one or more limited waivers with Fortress, there can be no assurance that we will be able to do so in the future.
We have historically failed, and may in the future fail, to satisfy one or more financial covenants under the Fortress Credit Agreement, and there can be no assurance that limited waivers or other relief will be available to us on acceptable terms or at all. From time to time, we and PhoenixOp, as borrower, have entered into amendments and received limited waivers of compliance with certain of these covenants, including in February 2026 with respect to the total secured leverage ratio, asset coverage ratio as of December 31, 2025, and the current ratio during the period from November 30, 2025 through and including January 31, 2026, and previously in connection with earlier amendments to the Fortress Credit Agreement. Such waivers, however, are discretionary, limited in scope and duration, and subject to conditions, and may not be available in the future. If we are unable to maintain compliance or to obtain waivers to the extent such waivers may be needed in the future, such failure could result in an event of default under the Fortress Credit Agreement. Upon the occurrence of an event of default, the administrative agent and the lenders under the Fortress Credit Agreement could exercise certain remedies, including accelerating amounts due and enforcing liens on the collateral, which could require us to seek additional financing on unfavorable terms, curtail capital expenditures, dispose of assets, or take other actions that could materially adversely affect our business, financial condition, results of operations, and cash flows. All of these events could result in your losing all or a part of your investment in the Registered Notes or Series A Preferred Shares, as applicable.
Risks Related to the Series A Preferred Shares
The Series A Preferred Shares represent perpetual equity interests in the Company, and holders of Series A Preferred Shares should not expect us to redeem any Series A Preferred Shares on any particular date.
The Series A Preferred Shares represent perpetual equity interests in the Company, and they have no maturity or mandatory redemption date and are not redeemable at the option of holders of Series A Preferred Shares under any circumstances. As a result, unlike our indebtedness, none of the Series A Preferred Shares will give rise to a claim for payment of a principal amount at a particular date. Instead, the Series A Preferred Shares may be redeemed by us at our option, at any time or from time to time, out of funds legally available for such redemption, at a redemption price payable in cash of $27.50 per Series A Preferred Share plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared.
Any decision we may make at any time to redeem the Series A Preferred Shares will depend upon, among other things, our evaluation of our capital position and general market conditions at that time. In addition, the Fortress Credit Agreement currently does, and instruments governing our other outstanding indebtedness may in the future, limit our ability to redeem the Series A Preferred Shares. For example, under the terms of the Fortress Credit Agreement we may only redeem the Series A Preferred Shares so long as, among other things, (i) no default or event of default has occurred and is continuing or would occur as a result of such redemption and (ii) immediately after giving effect to such redemption we remain in compliance with the financial covenants to maintain (a) a maximum total secured leverage ratio, (b) a minimum current ratio, and (c) a minimum asset coverage ratio on a pro forma basis. Further, under the terms of the Fortress Credit Agreement, we may only expend an aggregate amount of $5,000,000 to redeem Series A Preferred Shares in any fiscal quarter, which quarterly limit may be reduced by the amount of certain cash payments made during such quarter to the extent related to certain debt refinancing transactions. For a description of the terms of the Fortress Credit Agreement, including these ratios and limits on our ability to redeem the Series A Preferred Shares, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.” As a result, holders of the Series A Preferred Shares should expect to bear the financial risks of an investment in the Series A Preferred Shares for an indefinite period of time. Moreover, as further described below, the Series A Preferred Shares will rank junior to all of our existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against us.
The Series A Preferred Shares are junior and subordinated to our existing and future indebtedness, and your interests could be diluted by the issuance of additional preferred equity interests, including additional Series A Preferred Shares, and by other transactions.
The Series A Preferred Shares rank, with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution, or winding up: (a) senior to all classes or series of equity securities issued by us other than equity securities referred to in clauses (b) and (c) (“Junior Securities”); (b) on a parity with all equity
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securities issued by us with terms specifically providing that those equity securities rank on a parity with the Series A Preferred Shares with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution, or winding up (“Parity Securities”); (c) junior to all equity securities issued by us with terms specifically providing that those equity securities rank senior to the Series A Preferred Shares with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution, or winding up (“Senior Securities”); and (d) junior to all of our existing and future indebtedness and to the indebtedness and equity securities of our existing subsidiaries and any future subsidiaries.
We and our subsidiaries have incurred and may in the future incur substantial amounts of debt and other obligations, including Senior Securities, that will rank senior to the Series A Preferred Shares. As of December 31, 2025, after giving effect to the borrowing of an additional $75.0 million in aggregate under the Fortress Credit Agreement in February 2026, we would have had approximately $1,604.9 million of indebtedness outstanding. We have historically conducted, and from time to time may conduct, offerings of debt securities pursuant to registered transactions with the SEC and in transactions exempt from registration under the Securities Act and, as of December 31, 2025, we and our subsidiaries are authorized to issue up to $2.7 billion in additional debt securities through such offerings. We also have in the past and may in the future incur debt through term loan facilities, including under the Fortress Credit Agreement, or pursuant to securitization transactions, short-term offerings, and other capital market transactions. The payment of principal and interest on our existing and future debt reduces cash available for distribution, including to holders of the Series A Preferred Shares. If we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets to pay amounts due on any or all of the Series A Preferred Shares then outstanding and any Parity Securities that we have issued or may issue in the future, in which case, holders of the Series A Preferred Shares will share ratably with holders of such Parity Securities. The issuance of any Senior Securities or additional Parity Securities (including additional Series A Preferred Shares) would dilute the interests of the holders of the Series A Preferred Shares and could affect our ability to pay distributions on, redeem, or pay the liquidation preference on the Series A Preferred Shares. Certain of our existing or future debt instruments may restrict the authorization, payment, or setting apart of distributions for the Series A Preferred Shares. If we decide to issue additional debt or Senior Securities in the future, it is possible that these securities will be governed by an indenture or other instrument containing covenants restricting our operating flexibility. Future issuances and sales of Senior Securities, Parity Securities, or Junior Securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series A Preferred Shares to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
The Series A Preferred Shares have only limited voting rights.
Except as set forth in our governing documents or as otherwise required by Delaware law, holders of the Series A Preferred Shares generally will not have voting rights. Although the holders of the Series A Preferred Shares are entitled to limited protective voting rights with respect to certain matters and additional voting rights contingent upon the occurrence of certain events, each as described in the Third Amended and Restated Limited Liability Company Agreement of the Company and the Share Designation with Respect to the Series A Cumulative Redeemable Preferred Shares (together and as amended, supplemented, or otherwise modified from time to time, the “Third ARLLCA”), the Series A Preferred Shares will generally vote separately as a class along with all other series of Parity Securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series A Preferred Shares are limited and may be significantly diluted, and the holders of any such other series of Parity Securities that we may issue may be able to control or significantly influence the outcome of any vote.
Market interest rates and other factors may affect the value of the Series A Preferred Shares.
The price of the Series A Preferred Shares are and will be impacted by the distribution yield on the Series A Preferred Shares relative to market interest rates. An increase in market interest rates may lead prospective purchasers of the Series A Preferred Shares to expect a higher yield, and higher interest rates would likely increase our borrowing costs and potentially decrease funds available for distribution, including to the holders of the Series A Preferred Shares. Accordingly, higher market interest rates could cause the market price of the Series A Preferred Shares to decrease.
The trading prices of the Series A Preferred Shares will also depend on many other factors, which may change from time to time, including, but not limited to:
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In addition, over the last several years, prices of equity securities, including equity securities issued by companies in our industry, in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, the holders of Series A Preferred Shares may experience significant volatility, including a substantial and rapid decrease, in the market price of the Series A Preferred Shares. This volatility and any decrease may be driven by factors unrelated to our operating performance or prospects.
Your ability to transfer the Series A Preferred Shares at a time or price you desire may be limited by the absence of an active trading market, which may not develop or, if developed, might not stay sustainably active.
The Series A Preferred Shares are securities issued recently with no prior established trading market. An active trading market on the NYSE American for the Series A Preferred Shares may not develop or, even if it develops, may not last, in which case the trading price of the Series A Preferred Shares could be adversely affected, and your ability to transfer your Series A Preferred Shares will be limited.
We may fail to comply with the continued listing standards of the NYSE American, which may result in a delisting of our Series A Preferred Shares.
Although we expect to meet the minimum continued listing standards set forth in NYSE American listing standards, we cannot assure you that the Series A Preferred Shares will continue to be listed on NYSE American in the future. In order to continue listing the Series A Preferred Shares on NYSE American, we must maintain certain financial, distribution, and stock price levels and must maintain a minimum number of holders of Series A Preferred Shares.
If NYSE American determines to delist the Series A Preferred Shares and we are not able to list the Series A Preferred Shares on another national securities exchange, a reduction in some or all of the following may occur, each of which could have a material adverse effect on the holders of Series A Preferred Shares, as well as our business, financial condition, and results of operations:
In addition, the National Securities Markets Improvement Act of 1996 provides for the federal preemption of state securities laws of “covered securities” under certain circumstances. Under such act, covered securities include, among others, securities that are listed or approved on certain national securities exchanges (including NYSE American) and securities of an issuer that has securities listed or approved for listing on certain national securities exchanges where those securities are senior to the listed securities (for example, bonds issued by companies that have equity listed on a national securities exchange) or equal in rank to the listed securities. As a result, for so long as the Series A Preferred Shares are listed on the NYSE American, we will not be required to register or qualify in any state the offer, transfer, or sale of our Series A Preferred Shares and any of our other securities that are senior or equal in rank to the Series A Preferred Shares, including the Registered Notes. If the Series A Preferred Shares are delisted from the NYSE American and are not listed on another national securities exchange, the sale or transfer of the Series A Preferred Shares and any of our other securities that are senior or equal in rank to the Series A Preferred Shares, including the Registered Notes, may not be exempt from state securities laws. In such event, we may need to register or otherwise qualify such securities for any offer, transfer, or sale in certain states or determine that any such offer,
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transfer, or sale is exempt under applicable state securities laws. To the extent that we do not register or otherwise qualify such securities, or determine that such securities are not exempt under applicable state securities laws, we and the holders of such securities may be limited in the ability to offer, transfer, or sell such securities, which could have a material adverse effect on the value of such securities, on our ability to raise capital, and on our liquidity, business, financial condition, results of operations, and prospects.
Our ability to issue Parity Securities in the future could adversely affect the rights of holders of our Series A Preferred Shares.
We may in the future issue Parity Securities, which could have the effect of reducing the amounts available to the holders of the Series A Preferred Shares upon our liquidation, dissolution, or winding up if we do not have sufficient funds to pay all liquidation preferences of the Series A Preferred Shares and any such Parity Securities in full. It also would reduce amounts available to make distributions on the Series A Preferred Shares if we do not have sufficient funds to pay distributions on all outstanding Series A Preferred Shares and any such Parity Securities. In addition, future issuances and sales of Parity Securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series A Preferred Shares to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
We are not required to accumulate cash for the purpose of meeting our obligations to holders of the Series A Preferred Shares, which, along with the agreements governing our indebtedness, may limit the cash available to make distributions on the Series A Preferred Shares.
Pursuant to the terms of the Series A Preferred Shares, distributions on the Series A Preferred Shares will accrue whether or not we have earnings, whether there are assets legally available for the payment of such distributions, and whether such distributions are authorized or declared. However, future distributions on our capital stock, including the Series A Preferred Shares, will be at the discretion of our board of directors and will depend on, among other things, our results of operations, cash flow from operations, financial condition and capital requirements, any debt service requirements, and any other factors our board of directors deems relevant. Further, we are not required to accumulate cash for the purpose of meeting our obligations to holders of the Series A Preferred Shares and the Series A Preferred Shares are not subject to any sinking fund, which may reduce the extent of any cash available for distributions on the Series A Preferred Shares.
Our ability to pay cash distributions on the Series A Preferred Shares is also dependent on our ability to operate profitably and to generate cash from our operations. In addition, the Fortress Credit Agreement currently does, and instruments governing our other outstanding indebtedness may in the future, limit our ability to make distributions with respect to the Series A Preferred Shares. For example, under the terms of the Fortress Credit Agreement we may only declare or make a distribution with respect to the Series A Preferred Shares so long as, among other things, (i) no default or event of default has occurred and is continuing or would occur as a result of such distribution and (ii) immediately after giving effect to such distribution we remain in compliance with the financial covenants to maintain (a) a maximum total secured leverage ratio, (b) a minimum current ratio, and (c) a minimum asset coverage ratio on a pro forma basis. We cannot guarantee that we will be able to make cash distributions or what the actual distributions will be for any future period.
Whenever distributions on the Series A Preferred Shares are in arrears for six or more quarterly distribution periods (whether or not consecutive), the number of directors constituting our board of directors will be automatically increased by two and the holders of the Series A Preferred Shares will be entitled to vote for the election of those two additional directors at a special meeting called by us at the request of the holders of record of at least 25% of the outstanding Series A Preferred Shares, and at each subsequent annual meeting until all distributions accumulated on the Series A Preferred Shares for all past distribution periods and the then-current distribution period shall have been fully paid or declared and a sum sufficient for the payment thereof set aside for payment. Such remedies could have a material adverse effect on the Company’s financial condition.
Holders of Series A Preferred Shares may have liability to repay distributions.
Under certain circumstances, the holders of the Series A Preferred Shares may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Limited Liability Company Act (the “DLLCA”), we generally may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to members on account of their equity interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, unless
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otherwise agreed, for a period of three years from the date of an impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount.
Risks Related to Phoenix Equity’s Ownership of Our Common Shares and Certain LLCA Provisions
The interests of holders of our securities may conflict with the interests of our controlling shareholder.
Phoenix Equity owns 100% of our common equity interests and, as a result, other than under the limited circumstances described in the Third ARLLCA in which holders of the Series A Preferred Shares have specific designation rights, has the right to appoint all members to our board of directors. LJC controls Phoenix Equity and, therefore, indirectly has control over our management. As a result of this concentrated control, Phoenix Equity has the ability to determine corporate matters for the foreseeable future, including the power to, among other things:
Phoenix Equity may also be able to prevent or cause (either by way of a sale of their own stake or by approving our merger or sale of as a whole) a change of control of Phoenix Energy. Phoenix Equity’s control over us, and Phoenix Equity’s ability to prevent or cause a change of control of Phoenix Energy, may delay or prevent a change of control, or cause a change of control to occur at a time when it is not favored by other equityholders. Certain changes of control would constitute an event of default under the Fortress Credit Agreement and other indebtedness we may incur in the future, and would provide a redemption right to holders of the Reg A Bonds, but would not otherwise result in any default or prepayment event under our existing debt securities. As a result, our business and financial condition and the trading price of the Series A Preferred Shares could be adversely affected.
Our Third ARLLCA eliminates members of our board of directors’ fiduciary duties to us. If conflicts of interest arise among members of our board of directors and us, members of our board of directors may make decisions in their sole and absolute discretion, and shall be entitled to consider only such interests and factors as they desire, including their own interests.
Our Third ARLLCA contains provisions that eliminate the standards to which members of our board of directors would otherwise be held by state law, other than an implied contractual duty of good faith and fair dealing. To the extent permitted by any applicable law, members of our board of directors are able make any decision or determination with respect to the us or our business and affairs, whether pursuant to the terms of the Third ARLLCA or otherwise, in their sole and absolute discretion, and are entitled to consider only such interests and factors as they desire, including their own interests, and shall have no duty or obligation, fiduciary or otherwise, to give any consideration to any interest of or factors affecting us or any of our equityholders, including holders of Series A Preferred Shares. As a result, if members of our board of directors’ interests and duties to other entities conflict with our interests, members of our board of directors may favor their own interest over the interests of us and our equityholders.
Furthermore, the Third ARLLCA provides that, to the fullest extent permitted by DLLCA, members of our board of directors will not be liable to us or any of our equityholders for monetary damages unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such member engaged in fraud, and we will also indemnify such members of our board of directors to the fullest extent permitted by the DLLCA.
The Third ARLLCA contains an exclusive forum provision that may discourage lawsuits against us or our directors and officers.
The Third ARLLCA requires any dispute, controversy, or claim arising out of or relating to the Third ARLLCA, or any breach or termination, or the validity, of the Third ARLLCA, our internal affairs, the ownership, transfer, or rights or obligations of or with respect to any of our equity interests, or any action or inaction arising out of the foregoing, as well as any question of the arbitrator’s jurisdiction or the existence, scope, or validity of the Third ARLLCA’s arbitration mechanism, to be submitted, upon notice delivered by any party to such claim, to confidential, final, and binding arbitration. The foregoing arbitration requirements do not apply with respect to any suits brought to enforce a duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive
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jurisdiction. Furthermore, the Third ARLLCA provides that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in our equity securities is deemed to have received notice of and consented to these provisions.
These choice of forum provisions may result in increased costs to equityholders to bring a claim, limit an equityholder’s ability to bring a claim in a forum that it finds favorable for disputes with us or our directors, officers, or other employees, and may generally have the effect of discouraging lawsuits against us and our directors, officers, and other employees. However, equityholders are not deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. The enforceability of similar choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be inapplicable or unenforceable. If a court were to find these provisions in our Third ARLLCA to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.
Risks Related to Certain Tax Matters
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution could be reduced.
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited liability company under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our members. Because a tax would be imposed upon us as a corporation, the cash available to make principal and interest payments on the Notes and distribution payments on the Series A Preferred Shares could be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our members, which would cause a reduction in the value of an investment in us and cause a material adverse effect on our business, results of operations, and financial condition.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in Montana, Utah, Wyoming, Texas, North Dakota and Colorado, among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our members, which would cause a reduction in the value of your investment in us and could cause a material adverse effect on our business, results of operations, and financial condition.
The tax treatment of publicly traded partnerships or an investment in us could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our shares, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our shares, including eliminating partnership tax treatment for certain publicly traded partnerships, as well as reducing or eliminating certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies.
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Any changes to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes or interpretations thereof could cause a material adverse effect on our business, results of operations, and financial condition.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for Series A Preferred Shares and the cost of any IRS contest will reduce our cash available for distribution.
The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our shares and the price at which our shares trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our members because the costs will reduce our cash available for distribution.
Series A Preferred Shares that are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of Series A Preferred Shares) may be considered disposed. If so, the holder of such Series A Preferred Shares would no longer be treated for tax purposes as a partner with respect to those Series A Preferred Shares during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a holder of Series A Preferred Shares that are the subject of a securities loan may be considered as having disposed of the loaned shares. In that case, the holder of such Series A Preferred Shares may no longer be treated for tax purposes as a partner with respect to those Series A Preferred Shares during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those Series A Preferred Shares may not be reportable by the shareholder and any cash distributions received by the holder as to those Series A Preferred Shares could be fully taxable as ordinary income. You are encouraged to consult a tax advisor if you desire to assure your status as a partner and avoid the risk of gain recognition from a securities loan.
Certain tax consequences of the ownership of our Series A Preferred Shares, including treatment of distributions as guaranteed payments for the use of capital, are uncertain.
The tax treatment of distributions on our Series A Preferred Shares is uncertain. We treat the holders of the Series A Preferred Shares as partners for tax purposes and will treat distributions on the Series A Preferred Shares as guaranteed payments for the use of capital that will generally be taxable to the holders of the Series A Preferred Shares as ordinary income. Although a holder of Series A Preferred Shares will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution), we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, except in the case of our liquidation, the holders of Series A Preferred Shares are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Series A Preferred Shares. If the Series A Preferred Shares were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Series A Preferred Shares.
A holder of Series A Preferred Shares will be required to recognize a gain or loss on a sale of Series A Preferred Shares equal to the difference between the amount realized by such holder and such holder’s tax basis in the Series A Preferred Shares sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Series A Preferred Shares. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Share will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of such Series A Preferred Shares to acquire such Series A Preferred Shares. Gain or loss recognized by a holder of Series A Preferred Shares on the sale or exchange of a Preferred Share held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Series A Preferred Shares will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
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Investment in the Series A Preferred Shares by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes.
Distributions to non-U.S. holders of Series A Preferred Shares are subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Series A Preferred Shares may be required to file U.S. federal income tax returns in order to seek a refund of such excess. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Series A Preferred Shares.
Our treatment of distributions on our Series A Preferred Shares as guaranteed payments for the use of capital means that such distributions will not be eligible for the 20% deduction for qualified business income.
For taxable years ending on or before December 31, 2025, a non-corporate member may be entitled to a deduction equal to 20% of its “qualified business income” attributable to its interest in a partnership, subject to certain limitations. As described above, we will treat distributions on the Series A Preferred Shares as guaranteed payments for the use of capital, and under the applicable existing and proposed Treasury Regulations promulgated under the Code, a guaranteed payment for the use of capital will not be taken into account for purposes of computing qualified business income. As a result, distributions received by the holders of our Series A Preferred Shares will not be eligible for the 20% deduction for qualified business income. Holders of Series A Preferred Shares should consult their tax advisors regarding the availability of the deduction for qualified business income.
In addition, the rate at which holders of our Series A Preferred Shares are taxed on distributions we pay and the characterization of our distribution — be it ordinary income, capital gains, or a return of capital — could have an impact on the market price of our Series A Preferred Shares and, in turn, our ability to raise funds in new securities offerings. After we announce the expected characterization of dividend distributions we have paid, the actual characterization (and, therefore, the rate at which holders of our Series A Preferred Shares are taxed on the dividend distributions they have received) could vary from our expectation, including due to errors, changes made in the course of preparing our corporate tax returns, or changes made in response to an IRS audit, with the result that holders of our Series A Preferred Shares could incur greater income tax liabilities than expected.
Risks Related to Our Status as a Public Reporting Company
We only recently became a public reporting company, and the obligations associated with being a public reporting company will require significant resources and management attention.
As a recent public reporting company, we incur significant legal, regulatory, finance, accounting, investor relations, and other expenses that we previously did not incur as a private company, including costs associated with public company reporting requirements. We also have incurred and will continue to incur costs associated with the Sarbanes-Oxley Act of 2002 (“SOX”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act, and related rules implemented by the SEC. The expenses incurred by public reporting companies for reporting and corporate governance purposes have been increasing. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, although we are currently unable to estimate these costs with any degree of certainty. Our management currently does, and will need to continue to, devote a substantial amount of time to ensure that we comply with all of these additional requirements, diverting the attention of management away from revenue-producing activities. These laws and regulations also could make it more difficult or costly for us to obtain certain types of insurance, including director and officer liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. These laws and regulations could also make it more difficult for us to attract and retain qualified persons to serve as our executive officers. Furthermore, if we are unable to satisfy our obligations as a public reporting company, we could be subject to fines, sanctions, and other regulatory action and potentially civil litigation.
Failure to comply with requirements to design, implement, and maintain effective internal controls could have a material adverse effect on our business.
We were not previously required to evaluate our internal control over financial reporting in a manner that meets the standards of public reporting companies required by Section 404(a) of SOX (“Section 404”). As a public reporting company, we are subject to significant requirements for enhanced financial reporting and internal controls. The process
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of designing, implementing, and maintaining effective internal controls is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain a system of internal controls that is adequate to satisfy our reporting obligations as a public reporting company. If we are unable to establish or maintain appropriate internal financial reporting controls and procedures, it could cause us to fail to meet our reporting obligations on a timely basis, result in material misstatements in our consolidated financial statements, and harm our results of operations. In addition, we will be required, pursuant to Section 404, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting in our annual report for the 2026 fiscal year. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing, and possible remediation. Testing and maintaining internal controls may divert our management’s attention from other matters that are important to our business.
In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify deficiencies that we may not be able to remediate in time to meet the deadline imposed by SOX for compliance with the requirements of Section 404. In addition, we may encounter problems or delays in completing the remediation of any deficiencies identified by us or our independent registered public accounting firm in connection with the issuance of their attestation report. Our testing, or the subsequent testing (if required) by our independent registered public accounting firm, may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. Any material weaknesses could result in a material misstatement of our annual or quarterly financial statements or disclosures that may not be prevented or detected.
Specifically, in connection with the audits of our financial statements as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024, and 2023, our auditors identified several material weaknesses, including material weaknesses concerning our internal control over financial reporting. The material weaknesses identified were: (i) inadequate segregation of duties within key financial areas; (ii) entity-level controls that were not sufficiently designed, documented, or consistently maintained across the Committee of Sponsoring Organizations of the Treadway Commission components to provide reasonable assurance that material misstatements would be prevented or detected on a timely basis; (iii) ineffective processes for identifying and assessing risks impacting internal control over financial reporting; (iv) insufficient evaluation and determination as to whether components of internal controls were present and functioning; (v) ineffective information technology general controls supporting the financial reporting process; and (vi) ineffective controls over the completeness and accuracy of information used in the operation of control activities. Any steps we take to enhance our internal control environment and address the underlying cause of our material weaknesses may not be sufficient to remediate such material weaknesses or to avoid the identification of additional material weaknesses in the future.
We may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404, or our independent registered public accounting firm may not issue an unqualified opinion. If we are unable to remediate the identified material weaknesses, identify additional material weaknesses in the future, or otherwise fail to maintain an effective system of internal controls, or our independent registered public accounting firm is unable to provide us with an unqualified report (to the extent it is required to issue a report), investors could lose confidence in our reported financial information, which could have a material adverse effect on our business, results of operations, and financial condition.
We identified certain misstatements to our previously issued financial statements and have restated certain of our consolidated financial statements, which may create additional risks and uncertainties.
On September 12, 2024, our management determined that our audited consolidated financial statements for the fiscal year ended December 31, 2022 (the “GAAS 2022 Audited Financial Statements”), contained in our Annual Report on Form 1-K for that year, which was filed in compliance with our offerings under Regulation A, should no longer be relied upon due to certain errors in the GAAS 2022 Audited Financial Statements as addressed in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 250. We previously filed our Annual Report on Form 1-K for the fiscal year ended December 31, 2023 (the “2023 Form 1-K”) with the SEC on April 30, 2024, which filing contained corrected financial information for the fiscal year ended December 31, 2022. On September 26, 2024, we amended our 2023 Form 1-K (the “Form 1-K/A”) to reflect that we had restated the GAAS 2022 Audited Financial Statements.
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Subsequently, on March 7, 2025, our management concluded that each of (i) of our previously issued audited consolidated financial statements as of and for the fiscal years ended December 31, 2023 and 2022 (the “2023 and 2022 Audited Financial Statements”) contained in the Form 1-K/A, and (ii) our previously issued unaudited condensed consolidated financial statements for the fiscal semiannual periods ended June 30, 2024 and 2023 (the “Semiannual Unaudited Financial Statements” and, together with the 2023 and 2022 Audited Financial Statements, the “Existing Financial Statements”) contained in our Semiannual Report on Form 1-SA/A for the fiscal semiannual period ended June 30, 2024 (the “Form 1-SA/A”), filed with the SEC on September 26, 2024, should no longer be relied upon due to certain errors in the Existing Financial Statements, as addressed in FASB ASC Topic 250. In the Existing Financial Statements, we had immediately expensed debt issuance costs related to our unregistered bond offerings rather than amortizing them over the weighted-average term of the bonds, which resulted in overstated advertising and marketing expense, selling, general, and administrative expense, and payroll and payroll-related expense, and understated interest expense and loss on debt extinguishments. Additionally, in the Existing Financial Statements, we had previously expensed all interest costs, rather than capitalizing interest incurred on expenditures made in connection with our exploration and development projects as permitted under ASC Topic 835-20, “Capitalized Interest,” resulting in us overstating our interest expense and understating our oil and gas properties, in corresponding amounts. Accordingly, on March 27, 2025, we further amended the Form 1-K/A and Form 1-SA/A to reflect that we had restated the Existing Financial Statements.
As a result of the restatements, we may become subject to a number of additional risks and uncertainties and unanticipated costs for accounting, legal, and other fees and expenses. We may become subject to legal proceedings brought by regulatory or governmental authorities, or other proceedings, as a result of the errors or the related restatements, which could result in a loss of investor confidence or other reputational harm, additional defense, and other costs. In addition, we cannot assure you that additional restatements of financial statements will not arise in the future. Any of the foregoing impacts, individually or in aggregate, may have a material adverse effect on our business, financial position, and results of operations.
We are a “controlled company” within the meaning of the corporate governance standards of the NYSE American and rely, and may continue to rely, on exemptions from certain corporate governance standards.
Phoenix Equity holds all of our common shares, representing limited liability company interests, and, as a result, other than under the limited circumstances described in the Third ARLLCA in which holders of the Series A Preferred Shares have certain designation rights, Phoenix Equity has all of the voting power of the Company. As such, we are a “controlled company” under the rules of NYSE American. As a controlled company, we may elect not to comply with certain corporate governance requirements, including the requirements that:
For so long as we remain a “controlled company,” we may continue to rely on these exemptions. We have elected not to comply with certain corporate governance requirements under the rules, including the requirements above. As a result of these and any additional future elections, our board of directors currently does not and may not in the future have a majority of independent directors, we currently do not have and may never have a compensation committee consisting entirely of independent directors, and our directors currently are not and may not in the future be nominated or selected by independent directors.
We are a company with only preferred securities listed on the NYSE American and thus are only required to comply with certain corporate governance requirements, including with respect to our audit committee, in each case, to the extent required by Rule 10A-3 under the Exchange Act.
The rules of NYSE American provide that companies with only preferred or debt securities listed on NYSE American are only required to comply with the requirements to have a board that is composed of a majority of “independent directors,” an audit committee that is composed entirely of independent directors, an audit committee charter, and audit committee meeting requirements, responsibilities, and authorities, in each case, to the extent required
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by Rule 10A-3 under the Exchange Act. We are a company with only preferred securities listed on NYSE American and thus are only required to comply with such requirements to the extent required by Rule 10A-3 under the Exchange Act. We intend to comply with these reduced requirements and with the requirements of Rule 10A-3 under the Exchange Act. As a result, under these rules, we must have an audit committee of at least one director, which director must be independent. We currently have one director who qualifies as independent for audit committee purposes. As a result of these reduced requirements, you will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of NYSE American, particularly with respect to the audit committee requirements set forth in the rules of NYSE American.
General Risks
Our business could be adversely affected by unfavorable economic and political conditions.
Our future business and operations are sensitive to general business and economic conditions in the United States. National and regional economies and financial markets have become increasingly interconnected, which increases the possibilities that conditions in one country, region, or market might adversely impact companies in a different country, region, or market. Major economic or political disruptions, such as trade disputes between the United States and other countries, the slowing economy in China, conflicts in the Middle East, including the most recent conflict among Iran, the United States, Israel, and numerous other countries in the region and the conflict between Hamas and Israel in Gaza, the geopolitical tensions in South America, including the capture of the Venezuelan President and the recent use of kinetic strikes by the United States, the war in Ukraine and sanctions on Russia, and a potential economic slowdown in the United Kingdom and Europe, may have global negative economic and market repercussions. While we do not have or intend to have operations in every country or region listed above, such disruptions may nevertheless cause fluctuations in oil prices, which could impact our ability to generate cash flows and, in turn, make interest and principal payments to you. Additionally, the resulting political instability and societal disruption from these events and other factors, such as declining business and consumer confidence, may contribute to an economic slowdown and a recession. If the economic climate in the United States or abroad deteriorates, worldwide demand for oil and natural gas products could diminish, which could impact our and our third-party E&P operators’ operations, affect our ability and the ability of our third-party E&P operators to continue operations, and ultimately materially adversely impact our results of operations, financial condition, and cash flows.
Other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary, and trade policies and the new administration’s energy and environmental policies, all of which are beyond our control. Our business may also be adversely impacted by any future government rule, regulation, or order that may impose production limits, as well as pipeline capacity and storage constraints. We cannot predict the ultimate impact of these factors on our business, financial condition, and cash flows.
Any future global or domestic health crisis and uncertainty in the financial markets may adversely affect our ability to generate revenues.
The COVID-19 pandemic and other public health emergencies historically have had a material adverse effect on oil and gas businesses, due to governmental restrictions, associated repercussions, and operational challenges to supply and demand for oil and natural gas and the economy generally. The impacts of public health emergencies are uncertain and hard to predict. An extended period of global supply chain and economic disruption, as well as significantly decreased demand for oil and gas, due to any future public health emergencies, or otherwise, could have a material adverse effect on our business, access to sources of liquidity, and financial condition. Additionally, extended disruptions to the global economy are likely to cause fluctuations in oil prices and the timing of oil production, which could have a material adverse effect on our ability to generate cash flow, which in turn could limit our ability to pay principal and interest on our indebtedness, including the Registered Notes, and distributions on the Series A Preferred Shares.
Inflation could adversely impact our ability to control costs, including the operating expenses and capital costs of our third-party operating partners.
Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, the imposition of new tariffs, geopolitical issues, high levels of inflation, the availability and cost of credit and the U.S. financial market, and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the
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second half of 2021 and higher rates have generally persisted through 2025. We continue to develop plans to address these pressures and protect our access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on operating costs.
High inflation may cause our third-party operators to experience increasing costs for their operations, including oilfield services and equipment and increased personnel costs. Our operating partners may pass on such increased costs to us and have a negative effect on our business and financial condition. Sustained levels of high inflation have likewise caused the Federal Reserve and other central banks to increase interest rates multiple times in an effort to curb inflationary pressure on the costs of goods and services across the United States, which has had the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial results of our business. We cannot predict any future trends in the rate of inflation and any continued significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues for our products, would negatively impact our business, financial condition, and results of operations.
Increased attention to environmental, social, and governance (“ESG”) matters may impact our business.
Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. If we do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or if we are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business, financial condition, and results of operations could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on businesses to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to access capital markets.
In addition, organizations that provided information to investors on corporate governance and related matters have developed rating processes for evaluating business entities on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions.
Additionally, certain investors use these scores to benchmark businesses against their peers. If we are perceived as lagging, our investors may engage with such third-party organizations to require improved ESG disclosure or performance.
Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Although the impact of future Trump Administration policies is currently unknown, if this negative sentiment continues, it may reduce the availability of capital funding for potential development projects, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Investment in new business ventures could prove unsuccessful and adversely affect our business, financial condition, and results of operations.
In the future, we may invest in new business ventures. Such endeavors may involve risks and uncertainties, including greater-than-expected liabilities and expenses, as well as economic and regulatory challenges associated with operating in new businesses, regions, or countries. Investment into new business ventures may expose us to additional risks that could delay or prevent us from completing an investment or otherwise limit our ability to fully realize the anticipated benefits of an investment. The failure of any significant investment could adversely affect our business, financial condition, and results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Cybersecurity Risk Management and Strategy
We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information.
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As part of our risk management program, we reference various security industry frameworks and other guidance to help us assess, identify and manage cybersecurity risks. This does not imply that we meet any particular technical standards, specifications, or requirements, only that we use these frameworks as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.
Our cybersecurity risk management program is
Key elements of our cybersecurity risk management program include, but are not limited to, the following:
We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have
Cybersecurity Governance
Our board of directors considers cybersecurity risk as part of its risk oversight function and oversees the oversight of cybersecurity risks, including oversight of management’s implementation of our cybersecurity risk management program.
Our management team takes steps to stay informed about and monitor efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which may include: briefings from internal security personnel; threat intelligence and other information obtained from governmental, public, or private sources, including external consultants engaged by us, and alerts and reports produced by security tools deployed in our information technology environment.
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Item 2. Properties
The information required by Item 2 is contained in Item 1. Business.
Item 3. Legal Proceedings
We have been, are, and/or may in the future be involved in various legal proceedings, lawsuits, regulatory investigations, and other claims in the ordinary course of business. Such matters are subject to many uncertainties, and outcomes are not predictable with certainty. In particular, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Based on currently available information and after consultation with legal counsel, in the opinion of our management, none of the matters, disputes, or claims we are involved in, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations. We have not recorded any material accruals related to these matters as of December 31, 2025. See “Financial Statements and Supplementary Data—Note 16 – Commitments and Contingencies” of the notes to the consolidated financial statements included elsewhere in this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
All of our common equity securities are owned by Phoenix Equity and, therefore, there is no public trading market for our common equity securities.
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. Dalmore Group, LLC currently acts as managing
broker-dealer for the offering. The offering of the Registered Notes is ongoing and, as of the date of this Annual Report, the Company has sold $34.8 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.3 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.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.
Item 6. [Reserved]
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto presented in this Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. These forward-looking statements are dependent upon events, risks, and uncertainties that may be outside of our control. Our actual results could differ materially from those disclosed in these forward-looking statements. Factors that could cause or contribute to such differences include those described in “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements,” and elsewhere in this Annual Report. Our historical results are not necessarily indicative of the results that may be expected for any period in the future.
Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver-Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uinta, and Denver-Julesburg Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. Since 2020, we experienced significant growth in our business and operations. For example, in 2020, the E&P operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests. In the five years since then, the E&P operators of our properties have operated an additional 7,043 gross and 140.4 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 508 gross and 62.9 net productive development wells were drilled in 2025 alone. As of December 31, 2025, we had 4,478,932 and 562,318 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 9.9 million Boe for the year ended December 31, 2025. In the same period, our number of employees grew from 21 at December 31, 2020 to 206 at December 31, 2025. Additionally, beginning in mid-2023 we commenced direct drilling operations and we spudded our first wells in the third quarter of 2023; our first owned well commenced hydrocarbon production in January 2024 and, as of December 31, 2025, we had drilled a total of 116.0 gross and 105.7 net producing development and injection wells. We expect these direct drilling operations to be a core component of our business strategy going forward.
Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cash flows and primarily target assets that have a potential payback within the short to medium term and long-term cash flows.
As of December 31, 2025, we have completed 5,495 acquisitions from landowners and other mineral interest owners, representing approximately 562,318 NRAs of royalty assets and 626,597 of NMAs of leasehold assets since 2019. Over that same period, in addition to completing numerous small transactions, we completed more than 80 transactions larger than 1,000 NMAs that account for approximately 75% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2025, have sold 3,152 NMAs since 2019.
Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through PhoenixOp.
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For the years ended December 31, 2025, 2024, and 2023, we had revenue of $687.2 million, $281.2 million, and $118.1 million, respectively, net income (loss) of $66.1 million, $(24.8) million, and $(16.2) million, respectively, and EBITDA of $403.6 million, $150.7 million, and $65.9 million, respectively. As of December 31, 2025 and 2024, we had total assets of $1,806.8 million and $1,029.1 million, respectively, total liabilities of $1,728.6 million and $1,063.1 million, respectively (inclusive of total indebtedness of $1,529.9 million and $987.9 million, respectively), and retained earnings (accumulated deficit) of $29.7 million and $(34.5) million, respectively. Through 2025, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt and cash distributions on our preferred equity in 2025. Furthermore, as of December 31, 2025, we estimate that we will need to make approximately $1,064.1 million and $2,167.3 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $669.8 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt arrangements and cash distributions on our preferred equity for the foreseeable future, our current development plan contemplates capital expenditures in excess of operating cash flow in certain periods. Accordingly, we intend to fund a portion of our growth capital through a combination of operating cash flow, available borrowing capacity, and capital markets transactions, consistent with our historical practice. We regularly evaluate our capital structure and liquidity profile to maintain appropriate financial flexibility while executing our development plan. We may from time to time refinance, extend, or restructure portions of our indebtedness through capital markets transactions or private financing arrangements in order to optimize maturities and cost of capital. See “Risk Factors—Risks Related to Our Business and Operations—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 regarding interest rates and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” and “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Registered Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.”
Our Segments
We operate under three segments: Operating; Mineral and Non-operating; and Securities. Our Operating segment comprises our operations related to our drilling, extraction, and production activities, which today are conducted through PhoenixOp and its wholly-owned subsidiary, Firebird Services. The sale and marketing of our operated production are conducted through Firebird Marketing. Our Mineral and Non-operating segment comprises our operations for the acquisition of mineral interests and non-operated working interests in oil and gas properties, through which we share in the proceeds of the natural resources extracted and sold by the operator. Our Securities segment comprises our operations related to our capital raising activities associated with our debt securities offerings. Our management evaluates our performance and allocates resources based in part on segment operating profit, which is calculated as total segment revenue less operating expenses attributable to the segment, which includes allocated corporate costs.
Sources of Our Revenue
Our revenues have historically primarily constituted mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas, and NGL production from our interests. In 2024, we commenced sales of crude oil, natural gas, and NGL and began generating product sales in our operating segment through our wholly-owned subsidiary, PhoenixOp, which was formed for the purposes of drilling, extracting, and operating producing wells. Product sales accounted for over 63.7% of our total revenues for the year ended December 31, 2025, and we expect to derive a greater portion of our total revenues from product sales of crude oil, natural gas, and NGL in the future. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix, and volumes of production sold by our E&P operators, including PhoenixOp. We also derive revenues from performing saltwater disposal services on wells operated by PhoenixOp, as well as redemption fees charged to investors, generally in connection with the early redemption of their investments. Other revenue in the securities
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segment is derived almost exclusively from intersegment interest expense to the mineral and non-operating segment and the operating segment, and is eliminated in consolidation.
Principal Components of Our Cost Structure
Through PhoenixOp’s operations, we may incur certain production costs, including gathering, processing, and transportation costs, which are presented as a component of cost of sales on our consolidated statements of operations. As a non-operated working interest owner, we also incur lease operating expenses and, for both royalty and non-operated working interest ownership, our proportionate share of production, severance, and ad valorem taxes. In these circumstances, revenues are recognized net of production taxes and post-production expenses. Shared corporate costs that are overhead in nature and not directly associated with any one of our segments, including certain general and administrative expenses, executive or shared-function payroll costs, and certain limited marketing activities, are allocated to our segments based on usage and headcount, as appropriate. Cost of sales and depreciation, depletion, and amortization are not applicable to the securities segment.
Cost of Sales
Lease Operating Expenses
We incur lease operating expenses through: (i) PhoenixOp, where such costs are directly incurred through our own drilling and extraction activities; and (ii) our ownership of non-operated working interests, paying our pro rata share of cost of labor, equipment, maintenance, saltwater disposal, workover activity, and other miscellaneous costs. We generally expect that these expenses will increase as our number of mineral interest and non-operated working interests in oil and gas properties increase, and as our operating activities on wells operated by PhoenixOp continue to increase.
Production and Ad Valorem Taxes
Production taxes are typically paid at fixed rates on produced crude oil, natural gas, and NGL based on a percentage of revenues from our volume of products sold, established by federal, state, or local taxing authorities. Where properties are operated by third parties, the operator typically withholds and remits our proportionate share of production taxes on our behalf. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas, and NGL properties and, depending on the jurisdiction, are either withheld and remitted by the operator or paid directly by us. We generally expect that these expenses will increase as we continue oil and gas operating activities on operated properties, as production from such properties increase, and as our number of mineral interests and non-operated working interests in oil and gas properties increases.
Production Costs
Production costs consist of gathering, processing, and transportation expenses incurred to move our oil and gas production to a point of sale. We generally expect that these costs will increase as activity levels within our operating segment expand and as production volumes grow. For example, our production costs increased during 2024 and 2025 as additional wells came online and PhoenixOp began operated production from our initial operated properties.
Depreciation, Depletion, and Amortization
Depreciation, depletion, and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore, and develop crude oil, natural gas, and NGL. We follow the successful efforts method of accounting, pursuant to which we capitalize the costs of our proved crude oil, natural gas, and NGL mineral interest properties, which are then depleted on a unit-of-production basis based on proved crude oil, natural gas, and NGL reserve quantities. Our estimates of crude oil, natural gas, and NGL reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production. Any significant variance in these assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas, and NGL properties. We expect depletion to continue to increase in subsequent periods as we continue to invest in capital assets and our gross production of oil, gas, and other products increases. Depreciation, depletion, and amortization also includes the depreciation of office leasehold costs and other property and equipment.
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Selling, General, and Administrative Expense
Selling, general, and administrative expenses consist of costs incurred related to overhead, office expenses, and fees for professional services such as audit, tax, legal, and other consulting services.
Selling, general, and administrative expenses are allocated directly to a segment when there is a clear cost-benefit relationship between the expense and the segment that received the benefit. All other costs are aggregated within pools and allocated to each segment using a reasonable level-of-effort formula. We expect selling, general, and administrative expenses to continue to increase period over period as we continue to grow and capitalize on opportunities within each segment; however, we do expect the percentage of growth to begin to decline as our business matures. Certain overhead costs attributable to field-level operations are charged to operated wells and allocated to working interest owners. Amounts recovered from third parties are recorded as reductions of the related selling, general, and administrative expenses, which partially offsets increases in those costs as our operated well count grows.
Payroll and Payroll-Related Expense
Payroll and payroll-related expenses consist of personnel costs for executive and employee compensation and related benefits. Payroll and payroll-related expenses are allocated directly to the segment associated with a respective employee, with the exception of corporate personnel, whose costs are allocated to the segments based on a reasonable level-of-effort formula. We expect payroll expenses to continue to increase period over period as we continue to grow; however, we do expect the percentage of growth to begin to decline as our business matures.
Advertising and Marketing Expense
We incur advertising and marketing costs primarily in our securities segment. Advertising and marketing costs include third-party services related to public relations, market research, and the development of strategic initiatives, brand messaging, and communication materials that are produced for our investors to generate greater awareness and promote investor engagement. We expect advertising and marketing costs to vary from period to period as we undertake targeted campaigns or initiatives. Advertising and marketing costs are expensed as incurred.
Interest Expense, Net
We have financed a significant portion of our working capital requirements and acquisitions with borrowings under credit facilities and the issuance of debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under credit facilities and holders of our debt securities and amortization of debt discount and debt issuance costs in interest expense on our consolidated statements of operations. Interest expense is primarily incurred within the securities segment and allocated to the mineral and non-operating segment and the operating segment based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date. Allocated intersegment interest expense is eliminated in consolidation. We expect interest expense to continue to increase period over period as we raise additional capital to meet our objectives.
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
Volumes of Oil, Natural Gas, and NGL Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our operated wells and from our royalty and non-operated working interest assets. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
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Producing Wells, Spud Wells, and Permitted Wells
In order to track and assess the performance of our assets, we monitor the number of permitted wells, spud wells, completions, and producing wells across our operated properties, as well as our royalty and non-operated working interest assets, in an effort to evaluate near-term production growth.
Commodity Prices
Historically, oil, natural gas, and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for NYMEX WTI has ranged from a low of $47.47 per barrel in January 2021 to a high of $123.64 per barrel in March 2022. Over the same period, the Henry Hub spot market for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas, and NGL that our operators can produce economically. See “Risk Factors—Risks Related to Our Business and Operations—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.”
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually NYMEX WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX WTI price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX WTI price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btu and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. Natural gas, which currently has limitations on transportation in certain regions, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.
NGL. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.
EBITDA
We calculate EBITDA by adding back to net income (loss), interest income and expense and depreciation, depletion, and amortization expense for the respective periods. EBITDA is a non-GAAP supplemental financial measure used by our management to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. EBITDA does not represent and should not be considered an alternative to, or more meaningful than, net income (loss), income from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP as measures of financial performance. EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies.
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Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, primarily for the following reasons:
Acquisitions
There is typically a lag (e.g., six to eighteen months or longer) between when acquisitions are made and when those investments generate meaningful revenue. As a result, many of the investments we made in 2024 began generating revenue in 2025, and we anticipate the same delayed effect will occur from 2025 to 2026 and in the future as we continue to invest in new opportunities. We intend to pursue potential accretive acquisitions of additional mineral and royalty interests by capitalizing on our specialized software, as well as our management team’s expertise and relationships. We believe we will be well-positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we make may reduce, rather than increase, our cash flows and ability to make further investments in our business, satisfy our debt obligations, and make distributions on the Series A Preferred Shares. Additionally, it is possible that we will divest certain of our assets. Any such acquisitions or divestitures affect the comparability of our results of operations from period to period.
Supply, Demand, Market Risk, and Their Impact on Oil Prices
Commodity prices are a significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, and redemption of our debt. During the period from January 1, 2021 through December 31, 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. These prices experience large swings, sometimes on a day-to-day or week-to-week basis. For the year ended December 31, 2025, the average NYMEX WTI crude oil and natural gas prices were $65.39 per Bbl and $3.52 per MMBtu, respectively, representing a decrease of 14.7% and an increase of 60.5%, respectively, from the average NYMEX WTI prices for the year ended December 31, 2024. For the year ended December 31, 2024, the average NYMEX WTI crude oil and natural gas prices were $76.63 per Bbl and $2.19 per MMBtu, respectively, representing decreases of 1.2% and 13.5%, respectively, from the average NYMEX WTI prices for the year ended December 31, 2023.
Commodity prices over that time period have been volatile and will likely continue to be volatile in the future. Crude oil prices over that time period were impacted by a variety of factors affecting current and expected supply and demand dynamics, including strong demand for crude oil, domestic supply reductions, OPEC control measures, market disruptions resulting from broader macroeconomic drivers, such as the Russia-Ukraine war, sanctions on Russia, and conflicts and tensions in the Middle East. More recently, we believe that commodity prices, including crude oil prices, have been impacted by uncertainties regarding U.S. trade policies and concerns over slowing economic growth and resulting reductions in estimated oil consumption. Market prices for NGL are influenced by the components extracted, including ethane, propane, butane, and natural gasoline, among others, and the respective market pricing for each component. Other factors impacting supply and demand include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, and the strength of the U.S. dollar, as well as other factors, the majority of which are outside of our control.
We expect commodity price volatility to continue given the complex global dynamics of supply and demand that exist in the market. See “Risk Factors—Risks Related to Our Business and Operations—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” for further discussion on how volatility in commodity prices could impact us.
We are currently monitoring our operations and industry developments, including our drilling operations and production plans, in light of recent changes in the commodity price environment and industry volatility. While we believe we are well-positioned to navigate a lower-price environment, if the prices of commodities experience a significant drop following the recent rise due to the conflict in the Middle East or in the event of a prolonged period of lower commodity prices, our cash flows from operations would decrease and we may determine to adjust our business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. Such actions and circumstances would also impact our revenue, operating expenses, and
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liquidity. For example, we may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan.
We also continue to monitor the impact of the tariffs announced by the United States federal government in 2025. While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, we do not currently expect that the financial impact of the tariffs will be material to capital expenditures or operating expenses in 2026. We expect the primary impact of the tariffs to be on certain drilling input costs, such as steel casing.
Reporting and Compliance Expenses
We expect to incur incremental non-recurring costs related to our transition to being a public company, including the costs associated with the initial implementation of our improved internal controls and testing. We also expect to incur additional significant and recurring expenses as a public reporting company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, SOX compliance expenses, costs associated with the employment of additional personnel, increased independent auditor fees, increased legal fees, investor relations expenses, and increased director and officer insurance expenses. Certain of these general and administrative expenses are not included in our historical financial statements.
Derivatives
To reduce the impact of fluctuations in oil, natural gas, and NGL prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, natural gas, and NGL production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flows from operations.
Impairment
We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods. For example, commodity prices were volatile in 2025. As a result, we may be required to incur such impairments in future periods.
Debt and Interest Expense
We have a significant amount of debt and may incur significantly more in the future to finance, among other things, acquisitions, investments in PhoenixOp, and payments on our debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could have a negative effect on the demand for oil and natural gas, as well as our borrowing costs.
PhoenixOp
PhoenixOp was formed to manage and conduct drilling, extraction, and related oil and gas operating activities. PhoenixOp commenced the spudding of its first wells in the third quarter of 2023. During the year ended December 31, 2025, PhoenixOp placed 97 wells in production, and as of December 31, 2025, had 61 wells in various stages of development. Given its limited operations in 2023, PhoenixOp’s revenue was $1.2 million for that year and ramped to $125.6 million in 2024. For the year ended December 31, 2025, PhoenixOp’s operations increased, and its product sales revenue was $437.4 million. As more wells continue to commence production, and more properties are contributed to PhoenixOp for potential future drilling activities, we expect to derive a greater portion of our total revenues from PhoenixOp and our operating segment. We believe these operations represent a significant source of potential revenue growth. In addition, as PhoenixOp is an E&P operator, it incurs greater operating costs related to
82
Table of Contents
drilling, extraction, and related oil and gas operating activities than our mineral and non-operating activities. As a result, we expect our operating costs to increase as PhoenixOp’s operations expand and become a greater portion of our overall business. These operations continue to execute well against our business plan and we expect these trends to continue through 2026. We are currently monitoring PhoenixOp’s operations and industry developments in light of recent changes in the commodity price environment. While we believe our operations are well-positioned to navigate a lower-price environment, we may reduce operations, such as reducing rigs or completion crews, in response to a significant drop in the prices of commodities following the recent rise due to the conflict in the Middle East or prolonged periods of decreased commodity prices, which would reduce our revenue generated by PhoenixOp and could have an adverse effect on our business, financial condition, results of operations, and cash flows from operations.
2026 Outlook
The following table presents our current estimates of certain financial and operating results for the full year of 2026. These forward-looking statements reflect our expectations as of the date of this Annual Report, and are subject to substantial uncertainty. Our results are inherently unpredictable, may fluctuate significantly, and may be materially affected by many factors, such as fluctuations in commodity prices, changes in global economic and geopolitical conditions, which remain especially volatile, and changes in governmental regulations, among others. The following estimates are based on, among other things, our anticipated capital expenditures and drilling and operations programs, our ability to drill and complete wells consistent with our expectations, certain drilling, completion, and equipping cost assumptions, and certain well performance assumptions. In addition, achieving these estimates and maintaining the required drilling activity to achieve these estimates will depend on the availability of capital, the existing regulatory environment, commodity prices and differentials, rig and service availability, and actual drilling results, as well as other factors. Factors that could cause or contribute to changes of such estimates include those described in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” presented elsewhere in this Annual Report. If any of these risks and uncertainties actually occur or the assumptions underlying our estimates are incorrect, our actual operating results, costs and activities may be materially and adversely different from our expectations or guidance. For example, we are currently monitoring our operations and industry developments in light of recent changes in the commodity price environment and industry volatility. While we believe we are well-positioned to navigate a lower-price environment, which occasionally has materialized in the past years, a prolonged period of commodity prices below those assumed for purposes of our business plan and current estimates would have an adverse effect on our business, financial condition, results of operations, cash flows from operations, and 2026 outlook. If we adjust our business plan in response to such events, we may subsequently revise our 2026 outlook to reduce our expected ranges. For example, in such event, our expected ranges for revenue, net income, EBITDA, and production would likely decrease. Further, our total outstanding debt may increase to the extent we are required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. In addition, investors should recognize that the reliability of any guidance diminishes in as much as it involves estimates for figures further in the future, and so the further we are from the end of 2026 the more likely that our actual results will differ materially from our guidance. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.
|
|
Year Ending December 31, 2026 |
|
|||||
(dollars in thousands) |
|
Lower Range |
|
|
Upper Range |
|
||
Revenue(1) |
|
$ |
1,190,000 |
|
|
$ |
1,490,000 |
|
Total operating expenses |
|
$ |
965,000 |
|
|
$ |
1,030,000 |
|
Net income (loss)(2) |
|
$ |
(40,000 |
) |
|
$ |
65,000 |
|
EBITDA(3) |
|
$ |
475,000 |
|
|
$ |
605,000 |
|
Total outstanding debt(4) |
|
$ |
1,900,000 |
|
|
$ |
2,150,000 |
|
Production: |
|
|
|
|
|
|
||
Crude oil (Bbls) |
|
|
12,500,000 |
|
|
|
13,600,000 |
|
Natural gas (Mcf)(5) |
|
|
14,900,000 |
|
|
|
16,300,000 |
|
NGL (Bbls) |
|
|
475,000 |
|
|
|
520,000 |
|
Total (Boe) (6:1) |
|
|
15,458,333 |
|
|
|
16,836,667 |
|
Average daily production (Boe/d) (6:1) |
|
|
42,352 |
|
|
|
46,128 |
|
83
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Full-Year 2025 Financial and Operational Highlights
84
Table of Contents
Results of Operations for the Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024
The following table summarizes our consolidated results of operations for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
$ |
|
|
% |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Product sales |
|
$ |
437,421 |
|
|
$ |
125,649 |
|
|
$ |
311,772 |
|
|
|
248.1 |
% |
Mineral and royalty revenues |
|
|
124,999 |
|
|
|
152,999 |
|
|
|
(28,000 |
) |
|
|
(18.3 |
%) |
Purchased crude oil sales |
|
|
113,421 |
|
|
|
— |
|
|
|
113,421 |
|
|
NM |
|
|
Water services |
|
|
10,777 |
|
|
|
2,478 |
|
|
|
8,299 |
|
|
|
334.9 |
% |
Other revenue |
|
|
562 |
|
|
|
101 |
|
|
|
461 |
|
|
|
456.4 |
% |
Total revenues |
|
|
687,180 |
|
|
|
281,227 |
|
|
|
405,953 |
|
|
|
144.4 |
% |
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
|
155,206 |
|
|
|
63,947 |
|
|
|
91,259 |
|
|
|
142.7 |
% |
Depreciation, depletion, and amortization |
|
|
177,913 |
|
|
|
85,977 |
|
|
|
91,936 |
|
|
|
106.9 |
% |
Purchased crude oil expenses |
|
|
111,254 |
|
|
|
— |
|
|
|
111,254 |
|
|
NM |
|
|
Selling, general, and administrative |
|
|
26,049 |
|
|
|
29,167 |
|
|
|
(3,118 |
) |
|
|
(10.7 |
%) |
Payroll and payroll-related |
|
|
35,791 |
|
|
|
27,934 |
|
|
|
7,857 |
|
|
|
28.1 |
% |
Advertising and marketing |
|
|
1,971 |
|
|
|
679 |
|
|
|
1,292 |
|
|
|
190.3 |
% |
Loss on sale of assets |
|
|
— |
|
|
|
564 |
|
|
|
(564 |
) |
|
|
(100.0 |
%) |
Impairment expense |
|
|
3,421 |
|
|
|
564 |
|
|
|
2,857 |
|
|
|
506.6 |
% |
Total operating expenses |
|
|
511,605 |
|
|
|
208,832 |
|
|
|
302,773 |
|
|
|
145.0 |
% |
Income from operations |
|
|
175,575 |
|
|
|
72,395 |
|
|
|
103,180 |
|
|
|
142.5 |
% |
Other income (expenses) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest income |
|
|
1,653 |
|
|
|
705 |
|
|
|
948 |
|
|
|
134.5 |
% |
Interest expense, net |
|
|
(161,214 |
) |
|
|
(90,210 |
) |
|
|
(71,004 |
) |
|
|
(78.7 |
%) |
Gain (loss) on derivatives |
|
|
52,846 |
|
|
|
(5,986 |
) |
|
|
58,832 |
|
|
|
982.8 |
% |
Loss on debt extinguishments |
|
|
(2,752 |
) |
|
|
(1,697 |
) |
|
|
(1,055 |
) |
|
|
(62.2 |
%) |
Total other expenses |
|
|
(109,467 |
) |
|
|
(97,188 |
) |
|
|
(12,279 |
) |
|
|
(12.6 |
%) |
Net income (loss) |
|
$ |
66,108 |
|
|
$ |
(24,793 |
) |
|
$ |
90,901 |
|
|
|
366.6 |
% |
NM – not meaningful.
The following tables summarize our segment operating profit for the periods indicated:
|
|
Year Ended December 31, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
561,745 |
|
|
$ |
125,224 |
|
|
$ |
140,794 |
|
|
$ |
(140,583 |
) |
|
$ |
687,180 |
|
Total operating expenses |
|
|
(396,714 |
) |
|
|
(98,186 |
) |
|
|
(17,056 |
) |
|
|
351 |
|
|
|
(511,605 |
) |
Segment operating profit |
|
$ |
165,031 |
|
|
$ |
27,038 |
|
|
$ |
123,738 |
|
|
$ |
(140,232 |
) |
|
$ |
175,575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
Year Ended December 31, 2024 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
128,127 |
|
|
$ |
153,135 |
|
|
$ |
102,131 |
|
|
$ |
(102,166 |
) |
|
$ |
281,227 |
|
Total operating expenses |
|
|
(83,982 |
) |
|
|
(109,636 |
) |
|
|
(15,350 |
) |
|
|
136 |
|
|
|
(208,832 |
) |
Segment operating profit |
|
$ |
44,145 |
|
|
$ |
43,499 |
|
|
$ |
86,781 |
|
|
$ |
(102,030 |
) |
|
$ |
72,395 |
|
85
Table of Contents
The following table summarizes our production data and average realized prices for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
|
|
2025 |
|
|
2024 |
|
|
Amount |
|
|
% |
|
||||
Production Data: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbls) |
|
|
8,641,089 |
|
|
|
3,830,461 |
|
|
|
4,810,628 |
|
|
|
125.6 |
% |
Natural gas (Mcf) |
|
|
3,427,154 |
|
|
|
2,979,341 |
|
|
|
447,813 |
|
|
|
15.0 |
% |
NGL (Bbls) |
|
|
712,056 |
|
|
|
415,363 |
|
|
|
296,693 |
|
|
|
71.4 |
% |
Total (BOE)(6:1) |
|
|
9,924,337 |
|
|
|
4,742,381 |
|
|
|
5,181,956 |
|
|
|
109.3 |
% |
Average daily production (BOE/d) (6:1) |
|
|
27,190 |
|
|
|
12,993 |
|
|
|
14,197 |
|
|
|
109.3 |
% |
Average Realized Prices(a): |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
$ |
62.45 |
|
|
$ |
68.49 |
|
|
$ |
(6.04 |
) |
|
|
(8.8 |
%) |
Natural gas (Mcf) |
|
$ |
2.31 |
|
|
$ |
1.86 |
|
|
$ |
0.45 |
|
|
|
24.2 |
% |
NGL (Bbl) |
|
$ |
20.90 |
|
|
$ |
25.22 |
|
|
$ |
(4.32 |
) |
|
|
(17.1 |
%) |
Revenues
The following table shows the components of our revenue for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
$ |
|
|
% |
|
||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
$ |
426,415 |
|
|
$ |
123,340 |
|
|
$ |
303,075 |
|
|
|
245.7 |
% |
Natural gas |
|
|
2,318 |
|
|
|
315 |
|
|
|
2,003 |
|
|
|
635.9 |
% |
NGL |
|
|
8,688 |
|
|
|
1,994 |
|
|
|
6,694 |
|
|
|
335.7 |
% |
Total product sales |
|
|
437,421 |
|
|
|
125,649 |
|
|
|
311,772 |
|
|
|
248.1 |
% |
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
|
113,191 |
|
|
|
138,640 |
|
|
|
(25,449 |
) |
|
|
(18.4 |
%) |
Natural gas |
|
|
5,616 |
|
|
|
5,424 |
|
|
|
192 |
|
|
|
3.5 |
% |
NGL |
|
|
6,192 |
|
|
|
8,935 |
|
|
|
(2,743 |
) |
|
|
(30.7 |
%) |
Total mineral and royalty revenues |
|
|
124,999 |
|
|
|
152,999 |
|
|
|
(28,000 |
) |
|
|
(18.3 |
%) |
Purchased crude oil sales |
|
|
113,421 |
|
|
|
— |
|
|
|
113,421 |
|
|
NM |
|
|
Water services |
|
|
10,777 |
|
|
|
2,478 |
|
|
|
8,299 |
|
|
|
334.9 |
% |
Other revenue |
|
|
562 |
|
|
|
101 |
|
|
|
461 |
|
|
|
456.4 |
% |
Total revenues |
|
$ |
687,180 |
|
|
$ |
281,227 |
|
|
$ |
405,953 |
|
|
|
144.4 |
% |
NM – not meaningful.
Revenue was $687.2 million for the year ended December 31, 2025, as compared to $281.2 million for the same period in 2024, an increase of $406.0 million, or 144.4%. The increase was primarily attributable to a $311.8 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, $113.4 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp that did not exist in the prior period, and an $8.3 million increase in revenue from water disposal services, partially offset by a $28.0 million decrease in mineral and royalty revenues generated from our mineral and non-operating activities.
Operating Segment
Operating segment revenue was $561.7 million for the year ended December 31, 2025, as compared to $128.1 million for the same period in 2024, an increase of $433.6 million, or 338.5%. The increase was primarily attributable to a $311.8 million increase in product sales generated from our direct drilling, extraction, and related operating activities driven by additional wells placed into service, of which there were 97 producing wells in service as of December 31, 2025, as compared to 32 producing wells in service as of December 31, 2024, $113.4 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp beginning in April 2025, and an $8.3 million increase in water service revenue driven by higher disposal volumes, with 25.8 million barrels of saltwater disposed by Firebird Services for the year ended December 31, 2025, as compared to 7.8 million barrels during the same period in 2024, partially offset
86
Table of Contents
by a 20.8% decrease in the average realized price from $73.59/Bbl to $58.27/Bbl for crude oil in 2025 as compared to the same period in 2024.
Mineral and Non-operating Segment
Mineral and non-operating segment revenue was $125.2 million for the year ended December 31, 2025, as compared to $153.1 million for the same period in 2024, a decrease of $27.9 million, or 18.2%. The decrease in segment revenue was primarily driven by an 8.8% decrease in the average realized price from $68.49/Bbl to $62.45/Bbl for crude oil, a 17.1% decrease in the average realized price from $25.22/Bbl to $20.90/Bbl for NGL, and an 8.8% decrease in production volumes for crude oil in 2025 as compared to the same period in 2024.
Operating Expenses
Cost of Sales
The following table shows the components of our cost of sales for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
$ |
|
|
% |
|
||||
Cost of sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Lease operating expenses |
|
$ |
56,651 |
|
|
$ |
26,424 |
|
|
$ |
30,227 |
|
|
|
114.4 |
% |
Production costs |
|
|
52,457 |
|
|
|
12,066 |
|
|
|
40,391 |
|
|
|
334.8 |
% |
Production taxes |
|
|
46,098 |
|
|
|
25,457 |
|
|
|
20,641 |
|
|
|
81.1 |
% |
Total |
|
$ |
155,206 |
|
|
$ |
63,947 |
|
|
$ |
91,259 |
|
|
|
142.7 |
% |
Cost of sales was $155.2 million for the year ended December 31, 2025, as compared to $63.9 million for the same period in 2024, an increase of $91.3 million, or 142.9%. The increase was primarily driven by increased drilling, extraction, and related oil and gas operating activities associated with wells operated by PhoenixOp, partially offset by a decrease in cost of sales due to lower lease operating expense and severance taxes resulting from decreased crude oil production volumes from our acquisitions of mineral non-operated working interests for the year ended December 31, 2025 as compared to the same period in 2024.
Operating Segment
Operating segment cost of sales was $131.4 million for the year ended December 31, 2025, as compared to $33.8 million for the same period in 2024, an increase of $97.6 million, or 288.8%. The increase in segment cost of sales was driven by additional wells placed into service, of which there were 97 producing wells in service as of December 31, 2025, as compared to 32 producing wells in service as of December 31, 2024, resulting in increased lease operating expenses, production costs, and production and ad valorem taxes for the year ended December 31, 2025 as compared to the same period in 2024.
Mineral and Non-operating Segment
Mineral and non-operating segment cost of sales was $24.2 million for the year ended December 31, 2025, as compared to $30.2 million for the same period in 2024, a decrease of $6.0 million, or 19.9%. The decrease in segment cost of sales was primarily attributable to lower lease operating expense and severance taxes resulting from an 8.8% decrease in crude oil production volumes from our acquisitions of mineral and non-operated working interests for the year ended December 31, 2025 as compared to the same period in 2024.
87
Table of Contents
Depreciation, Depletion, and Amortization Expense
The following table shows the components of our depletion, depreciation, and amortization expense for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
$ |
|
|
% |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Depletion |
|
$ |
177,639 |
|
|
$ |
85,706 |
|
|
$ |
91,933 |
|
|
|
107.3 |
% |
Depreciation |
|
|
58 |
|
|
|
91 |
|
|
|
(33 |
) |
|
|
(36.3 |
%) |
Amortization |
|
|
47 |
|
|
|
— |
|
|
|
47 |
|
|
NM |
|
|
Accretion on asset retirement obligations |
|
|
169 |
|
|
|
180 |
|
|
|
(11 |
) |
|
|
(6.1 |
%) |
Total |
|
$ |
177,913 |
|
|
$ |
85,977 |
|
|
$ |
91,936 |
|
|
|
106.9 |
% |
NM – not meaningful.
Depreciation, depletion, and amortization expense was $177.9 million for the year ended December 31, 2025, as compared to $86.0 million for the same period in 2024, an increase of $91.9 million, or 106.9%, primarily due to a $104.8 million increase in depletion expense within the operating segment driven by increases in our depletable cost bases, partially offset by a $12.9 million decrease within the mineral and non-operating segment, primarily due to a lower depletion rate driven by reduced realized production volumes.
Operating Segment
Depletion for the operating segment was $140.2 million for the year ended December 31, 2025, as compared to $35.4 million for the same period in 2024, an increase of $104.8 million, or 296.0%, primarily due to increases in the depletable cost bases, partially offset by a lower depletion rate for the year ended December 31, 2025 as compared to the same period in 2024. The lower depletion rate is primarily attributable to significant growth in proved reserves due to drilling activity by PhoenixOp.
Mineral and Non-operating Segment
Depletion for the mineral and non-operating segment was $37.7 million for the year ended December 31, 2025, as compared to $50.6 million for the same period in 2024, a decrease of $12.9 million, or 25.5%. On a per unit basis, depletion expense was $17.92 per Boe and $18.13 per Boe for the years ended December 31, 2025 and 2024, respectively, a decrease of $0.21 per Boe, driven by a lower depletion rate, primarily due to reduced realized production volumes.
Purchased Crude Oil Expense
Purchased crude oil expense was $111.3 million for the year ended December 31, 2025, with no comparable activity for the same period in 2024. This change is attributable to the commencement of marketing activities in April 2025 through Firebird Marketing within the operating segment. Purchased crude oil expense represents the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $26.0 million for the year ended December 31, 2025, as compared to $29.2 million for the same period in 2024, a decrease of $3.2 million, or 11.0%. The decrease was primarily due to a $7.7 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, and a $6.6 million decrease in fees associated with professional legal services. The decrease was partially offset by a $4.5 million increase in allocated corporate overhead, a $4.2 million increase in fees associated with land acquisition and title work, a $1.8 million increase in financing-related costs, including administrative costs associated with our securities offerings, and a $0.6 million increase in contract labor costs.
Operating Segment
Selling, general, and administrative expense for the operating segment was $2.1 million for the year ended December 31, 2025, as compared to $6.2 million for the same period in 2024, a decrease of $4.1 million, or 66.1%, primarily due to a $7.7 million increase in the overhead attributable to field-level operations charged to operated wells,
88
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which reduced selling, general, and administrative expense, and decreased allocated professional legal fees of $1.6 million, partially offset by increased allocated corporate overhead of $2.6 million, increased fees charged by purchasers for early revenue payments received of $1.2 million, and increased office expenses and fees for professional services within the operating segment of $1.2 million.
Mineral and Non-operating Segment
Selling, general, and administrative expense for the mineral and non-operating segment was $18.3 million for the year ended December 31, 2025, as compared to $14.4 million for the same period in 2024, an increase of $3.9 million, or 27.1%. The increase was primarily due to increased fees associated with land acquisition and title work of $4.2 million and increased allocated corporate overhead of $1.3 million, partially offset by decreased allocated professional legal fees of $1.6 million.
Securities Segment
Selling, general, and administrative expense for the securities segment was $5.6 million for the year ended December 31, 2025, as compared to $8.6 million for the same period in 2024, a decrease of $3.0 million, or 34.9%, primarily due to decreased professional legal service fees of $3.5 million, partially offset by increased administrative costs associated with our securities offerings of $0.7 million.
Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $35.8 million for the year ended December 31, 2025, as compared to $27.9 million for the same period in 2024, an increase of $7.9 million, or 28.3%, primarily as a result of increased employee compensation and headcount. Employee headcount increased from 135 employees at December 31, 2024 to 206 employees at December 31, 2025. ]
Operating Segment
Payroll and payroll-related expense for the operating segment was $11.8 million for the year ended December 31, 2025, as compared to $8.6 million for the same period in 2024, an increase of $3.2 million, or 37.2%, primarily due to the increased number of personnel engaged in our oil and gas operating activities, partially offset by a $4.1 million increase in labor charged out to wells operated by us, which reduced payroll and payroll-related expense.
Mineral and Non-operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $14.5 million for the year ended December 31, 2025, as compared to $13.3 million for the same period in 2024, an increase of $1.2 million, or 9.0%, due to increased activity in acquiring leasehold and mineral assets.
Securities Segment
Payroll and payroll-related expense for the securities segment was $9.5 million for the year ended December 31, 2025, as compared to $6.1 million for the same period in 2024, an increase of $3.4 million, or 55.7%, primarily due to increased employee compensation and the increased number of personnel engaged in the administration and management of our securities offerings.
Advertising and Marketing Expense
Advertising and marketing expense was $2.0 million for the year ended December 31, 2025, as compared to $0.7 million for the same period in 2024, an increase of $1.3 million, or 185.7%, primarily due to increased marketing expenses related to our debt securities offerings and offering of Series A Preferred Shares.
Loss on Sale of Assets
Loss on sale of assets was $0.6 million for the year ended December 31, 2024 as a result of the disposition of certain mineral interests in the Williston Basin within the mineral and non-operating segment, with no comparable activity in the current-year period.
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Table of Contents
Impairment Expense
Impairment expense was $3.4 million for the year ended December 31, 2025, as compared to $0.6 million for the same period in 2024, an increase of $2.8 million, or 466.7%, primarily as a result of lease expirations within the mineral and non-operating segment.
Other Expenses
Interest Expense, Net
Interest expense, net, was $161.2 million for the year ended December 31, 2025, as compared to $90.2 million for the same period in 2024, an increase of $71.0 million, or 78.7%. The increase was primarily due to a $48.3 million increase in interest costs associated with sales of our unregistered debt securities and Registered Notes, which increased from $737.9 million outstanding at December 31, 2024 to $1,079.9 million outstanding at December 31, 2025, with no significant changes in interest rates between the periods, a $36.2 million increase in interest costs associated with the Fortress Credit Agreement, and a $3.9 million increase in interest costs associated with securities-related debt issuance costs for the year ended December 31, 2025. The increase was partially offset by decreased interest costs of $5.1 million associated with merchant cash advances and a line of credit, which were previously outstanding as of December 31, 2024 but were repaid in full prior to the beginning of 2025, $0.3 million of decreased interest costs associated with deferred closings associated with our mineral acquisitions, and a $11.9 million increase in capitalized interest primarily due to higher qualifying asset expenditures.
Gain (Loss) on Derivatives
Gain on derivatives was $52.8 million for the year ended December 31, 2025, as compared to a loss on derivatives of $6.0 million for the same period in 2024, an increase of $58.8 million, or 980.0%, primarily as a result of favorable changes in the mark-to-market value of commodity derivatives entered into for the year ended December 31, 2025, with limited comparable activity for the same period in 2024.
Loss on Debt Extinguishments
Loss on debt extinguishments was $2.8 million for the year ended December 31, 2025, as compared to $1.7 million for the same period in 2024, an increase of $1.1 million, or 64.7%. The increase was primarily due to increased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our debt offerings, of which $19.2 million of bonds were redeemed during the year ended December 31, 2025, as compared to $17.7 million of bonds redeemed for the same period in 2024.
The following table summarizes the par value of bonds redeemed for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
$ |
|
|
% |
|
||||
Reg D Bonds |
|
|
|
|
|
|
|
|
|
|
|
|
||||
August 2023 506(c) Bonds |
|
$ |
11,023 |
|
|
$ |
12,426 |
|
|
$ |
(1,403 |
) |
|
|
(11.3 |
%) |
Senior Reg D Bonds |
|
|
510 |
|
|
|
100 |
|
|
|
410 |
|
|
|
410.0 |
% |
December 2022 506(c) Bonds |
|
|
1,677 |
|
|
|
1,592 |
|
|
|
85 |
|
|
|
5.3 |
% |
Total Reg D Bonds |
|
|
13,210 |
|
|
|
14,118 |
|
|
|
(908 |
) |
|
|
(6.4 |
%) |
Reg A Bonds |
|
|
1,972 |
|
|
|
2,306 |
|
|
|
(334 |
) |
|
|
(14.5 |
%) |
Adamantium Bonds |
|
|
3,820 |
|
|
|
1,319 |
|
|
|
2,501 |
|
|
|
189.6 |
% |
Registered Notes |
|
|
140 |
|
|
|
— |
|
|
|
140 |
|
|
NM |
|
|
Exchange Notes |
|
|
40 |
|
|
|
— |
|
|
|
40 |
|
|
NM |
|
|
Total |
|
$ |
19,182 |
|
|
$ |
17,743 |
|
|
$ |
1,439 |
|
|
|
8.1 |
% |
NM – not meaningful.
90
Table of Contents
Results of Operations for the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
The following table summarizes our consolidated results of operations for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2024 |
|
|
2023 |
|
|
$ |
|
|
% |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Product sales |
|
$ |
125,649 |
|
|
$ |
— |
|
|
$ |
125,649 |
|
|
NM |
|
|
Mineral and royalty revenues |
|
|
152,999 |
|
|
|
118,088 |
|
|
|
34,911 |
|
|
|
29.6 |
% |
Water services |
|
|
2,478 |
|
|
|
— |
|
|
|
2,478 |
|
|
NM |
|
|
Other revenue |
|
|
101 |
|
|
|
17 |
|
|
|
84 |
|
|
|
494.1 |
% |
Total revenues |
|
|
281,227 |
|
|
|
118,105 |
|
|
|
163,122 |
|
|
|
138.1 |
% |
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
|
63,947 |
|
|
|
19,733 |
|
|
|
44,214 |
|
|
|
224.1 |
% |
Depreciation, depletion, and amortization |
|
|
85,977 |
|
|
|
34,228 |
|
|
|
51,749 |
|
|
|
151.2 |
% |
Advertising and marketing |
|
|
679 |
|
|
|
4,136 |
|
|
|
(3,457 |
) |
|
|
(83.6 |
%) |
Selling, general, and administrative |
|
|
29,167 |
|
|
|
14,314 |
|
|
|
14,853 |
|
|
|
103.8 |
% |
Payroll and payroll-related |
|
|
27,934 |
|
|
|
12,733 |
|
|
|
15,201 |
|
|
|
119.4 |
% |
Loss on sale of assets |
|
|
564 |
|
|
|
— |
|
|
|
564 |
|
|
NM |
|
|
Impairment expense |
|
|
564 |
|
|
|
974 |
|
|
|
(410 |
) |
|
|
(42.1 |
%) |
Total operating expenses |
|
|
208,832 |
|
|
|
86,118 |
|
|
|
122,714 |
|
|
|
142.5 |
% |
Income from operations |
|
|
72,395 |
|
|
|
31,987 |
|
|
|
40,408 |
|
|
|
126.3 |
% |
Other income (expenses) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest income |
|
|
705 |
|
|
|
66 |
|
|
|
639 |
|
|
|
968.2 |
% |
Interest expense, net |
|
|
(90,210 |
) |
|
|
(47,882 |
) |
|
|
(42,328 |
) |
|
|
(88.4 |
%) |
Loss on derivatives |
|
|
(5,986 |
) |
|
|
(32 |
) |
|
|
(5,954 |
) |
|
|
(18,606.3 |
%) |
Loss on debt extinguishments |
|
|
(1,697 |
) |
|
|
(328 |
) |
|
|
(1,369 |
) |
|
|
(417.4 |
%) |
Total other expenses |
|
|
(97,188 |
) |
|
|
(48,176 |
) |
|
|
(49,012 |
) |
|
|
(101.7 |
%) |
Net loss |
|
$ |
(24,793 |
) |
|
$ |
(16,189 |
) |
|
$ |
(8,604 |
) |
|
|
(53.1 |
%) |
NM – not meaningful.
The following tables summarize our segment operating profit (loss) for the periods indicated:
|
|
Year Ended December 31, 2024 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
128,127 |
|
|
$ |
153,135 |
|
|
$ |
102,131 |
|
|
$ |
(102,166 |
) |
|
$ |
281,227 |
|
Total operating expenses |
|
|
(83,982 |
) |
|
|
(109,636 |
) |
|
|
(15,350 |
) |
|
|
136 |
|
|
|
(208,832 |
) |
Segment operating profit |
|
$ |
44,145 |
|
|
$ |
43,499 |
|
|
$ |
86,781 |
|
|
$ |
(102,030 |
) |
|
$ |
72,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
Year Ended December 31, 2023 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
1,225 |
|
|
$ |
116,902 |
|
|
$ |
40,509 |
|
|
$ |
(40,531 |
) |
|
$ |
118,105 |
|
Total operating expenses |
|
|
(6,725 |
) |
|
|
(67,884 |
) |
|
|
(11,548 |
) |
|
|
39 |
|
|
|
(86,118 |
) |
Segment operating profit (loss) |
|
$ |
(5,500 |
) |
|
$ |
49,018 |
|
|
$ |
28,961 |
|
|
$ |
(40,492 |
) |
|
$ |
31,987 |
|
91
Table of Contents
The following table summarizes our production data and average realized prices for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
Amount |
|
|
% |
|
||||
Production Data: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbls) |
|
|
3,830,461 |
|
|
|
1,446,928 |
|
|
|
2,383,533 |
|
|
|
164.7 |
% |
Natural gas (Mcf) |
|
|
2,979,341 |
|
|
|
2,152,939 |
|
|
|
826,402 |
|
|
|
38.4 |
% |
NGL (Bbls) |
|
|
415,363 |
|
|
|
201,454 |
|
|
|
213,909 |
|
|
|
106.2 |
% |
Total (BOE)(6:1) |
|
|
4,742,381 |
|
|
|
2,007,205 |
|
|
|
2,735,176 |
|
|
|
136.3 |
% |
Average daily production (BOE/d) (6:1) |
|
|
12,993 |
|
|
|
5,499 |
|
|
|
7,494 |
|
|
|
136.3 |
% |
Average Realized Prices(a): |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
$ |
68.49 |
|
|
$ |
73.10 |
|
|
$ |
(4.61 |
) |
|
|
(6.3 |
%) |
Natural gas (Mcf) |
|
$ |
1.86 |
|
|
$ |
3.15 |
|
|
$ |
(1.29 |
) |
|
|
(41.0 |
%) |
NGL (Bbl) |
|
$ |
25.22 |
|
|
$ |
27.50 |
|
|
$ |
(2.28 |
) |
|
|
(8.3 |
%) |
Revenues
The following table shows the components of our revenue for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2024 |
|
|
2023 |
|
|
$ |
|
|
% |
|
||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
$ |
123,340 |
|
|
$ |
— |
|
|
$ |
123,340 |
|
|
NM |
|
|
Natural gas |
|
|
315 |
|
|
|
— |
|
|
|
315 |
|
|
NM |
|
|
NGL |
|
|
1,994 |
|
|
|
— |
|
|
|
1,994 |
|
|
NM |
|
|
Total product sales |
|
|
125,649 |
|
|
|
— |
|
|
|
125,649 |
|
|
NM |
|
|
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
|
138,640 |
|
|
|
105,771 |
|
|
|
32,869 |
|
|
|
31.1 |
% |
Natural gas |
|
|
5,424 |
|
|
|
6,790 |
|
|
|
(1,366 |
) |
|
|
(20.1 |
%) |
NGL |
|
|
8,935 |
|
|
|
5,527 |
|
|
|
3,408 |
|
|
|
61.7 |
% |
Total mineral and royalty revenues |
|
|
152,999 |
|
|
|
118,088 |
|
|
|
34,911 |
|
|
|
29.6 |
% |
Water services |
|
|
2,478 |
|
|
|
— |
|
|
|
2,478 |
|
|
NM |
|
|
Other revenue |
|
|
101 |
|
|
|
17 |
|
|
|
84 |
|
|
|
494.1 |
% |
Total revenues |
|
$ |
281,227 |
|
|
$ |
118,105 |
|
|
$ |
163,122 |
|
|
|
138.1 |
% |
NM – not meaningful.
Revenue was $281.2 million for the year ended December 31, 2024, as compared to $118.1 million for the same period in 2023, an increase of $163.1 million, or 138.1%. The increase was primarily attributable to a $125.6 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities and a $34.9 million increase in mineral and royalty revenues generated from our mineral and non-operating activities.
Operating Segment
Operating segment revenue was $128.1 million for the year ended December 31, 2024, as compared to $1.2 million for the same period in 2023, an increase of $126.9 million. The increase in segment revenue was driven by the commencement of drilling activities by PhoenixOp. PhoenixOp began its operations in the third quarter of 2023 with the acquisition of five producing wells from another operator. As a result, segment revenues for the year ended December 31, 2023 were not material. PhoenixOp commenced production on its operated wells in 2024 and placed into service 32 additional wells as of December 31, 2024, resulting in increased segment revenue for the year ended December 31, 2024 as compared to the same period in 2023.
Mineral and Non-operating Segment
Mineral and non-operating segment revenue was $153.1 million for the year ended December 31, 2024, as compared to $116.9 million for the same period in 2023, an increase of $36.2 million, or 31.0%. The increase in segment revenue was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties, which have expanded significantly in recent years. Acquisitions of such interests
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Table of Contents
generally generate revenue in subsequent periods (e.g., on a six to eighteen-month lag). As a result, our mineral and non-operating segment revenue has increased over time as our portfolio of mineral interests and non-operated working interests in oil and gas properties has expanded. During the year ended December 31, 2024, we closed 1,802 unique transactions that added 134,809 NMAs of leasehold interests and 52,959 NRAs of mineral interests to our portfolio, as compared to 790 unique transactions, 64,569 NMA of leasehold interests, and 15,086 NRAs of mineral interests for the same period in 2023. The increase in our mineral and non-operating segment revenue was partially offset by lower commodity prices and higher post-production costs passed through to us relative to the increase in production volumes.
Operating Expenses
Cost of Sales
The following table shows the components of our cost of sales for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2024 |
|
|
2023 |
|
|
$ |
|
|
% |
|
||||
Cost of sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Lease operating expenses |
|
$ |
26,424 |
|
|
$ |
9,011 |
|
|
$ |
17,413 |
|
|
|
193.2 |
% |
Production costs |
|
|
12,066 |
|
|
|
50 |
|
|
|
12,016 |
|
|
|
24,032.0 |
% |
Production taxes |
|
|
25,457 |
|
|
|
10,672 |
|
|
|
14,785 |
|
|
|
138.5 |
% |
Total |
|
$ |
63,947 |
|
|
$ |
19,733 |
|
|
$ |
44,214 |
|
|
|
224.1 |
% |
Cost of sales was $63.9 million for the year ended December 31, 2024, as compared to $19.7 million for the same period in 2023, an increase of $44.2 million, or 224.4%. The increase was primarily driven by the commencement of our direct drilling, extraction, and related oil and gas operating activities in 2024, as well as an increase in our mineral interests and non-operated working interests in oil and gas properties.
Operating Segment
Operating segment cost of sales was $33.8 million for the year ended December 31, 2024, as compared to $0.5 million for the same period in 2023, an increase of $33.3 million. The increase in segment cost of sales was driven by the commencement of operated production from newly drilled wells by PhoenixOp in the first quarter of 2024, at which time we began to recognize lease operating expenses, production and ad valorem taxes, and production costs in our operating segment. PhoenixOp began its operations in the third quarter of 2023, when it became the operator of five producing wells acquired from another operator. As a result, there were no material cost of sales incurred for the year ended December 31, 2023.
Mineral and Non-operating Segment
Mineral and non-operating segment cost of sales was $30.2 million for the year ended December 31, 2024, as compared to $19.3 million for the same period in 2023, an increase of $10.9 million, or 56.5%. The increase in segment cost of sales was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties and the resulting increase in lease operating expenses and production taxes.
Depreciation, Depletion, and Amortization Expense
The following table shows the components of our depletion, depreciation, and amortization expense for the periods presented:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2024 |
|
|
2023 |
|
|
$ |
|
|
% |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Depletion |
|
$ |
85,706 |
|
|
$ |
34,035 |
|
|
$ |
51,671 |
|
|
|
151.8 |
% |
Depreciation |
|
|
91 |
|
|
|
136 |
|
|
|
(45 |
) |
|
|
(33.1 |
%) |
Accretion on asset retirement obligations |
|
|
180 |
|
|
|
57 |
|
|
|
123 |
|
|
|
215.8 |
% |
Total |
|
$ |
85,977 |
|
|
$ |
34,228 |
|
|
$ |
51,749 |
|
|
|
151.2 |
% |
Depreciation, depletion, and amortization expense was $86.0 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023, an increase of $51.8 million, or 151.5%, primarily due to an
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increase in our depletable bases within both the operating and mineral and non-operating segments. On a per unit basis, depletion expense was $18.13 per Boe and $17.06 per Boe for the years ended December 31, 2024 and 2023, respectively. The increase in our depletion expense per Boe was predominantly driven by a higher depletion rate for the year ended December 31, 2024 as compared to the year ended December 31, 2023, as a direct result of the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. 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.
Operating Segment
Depletion for the operating segment was $35.4 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023 due to limited operations in the period.
Mineral and Non-operating Segment
Depletion for the mineral and non-operating segment was $50.6 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023, an increase of $16.4 million, or 48.0%. The increase in our segment depletion expense was predominantly driven by increased production and increased capital expenditures.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $29.2 million for the year ended December 31, 2024, as compared to $14.3 million for the same period in 2023, an increase of $14.9 million, or 104.2%. The increase was primarily due to a $9.8 million increase in corporate overhead costs not directly associated with the segments, but which have been allocated to the segments based on headcount and a level-of-effort formula, including an $8.8 million increase in legal, accounting, and consulting professional services fees, a $2.8 million increase in costs associated with our capital raise initiatives in our securities segment, and a $2.8 million increase in fees associated with land acquisition and title work within our mineral and non-operating segment, as further described below.
Operating Segment
Selling, general, and administrative expense for the operating segment was $6.2 million for the year ended December 31, 2024, as compared to $2.8 million for the same period in 2023, an increase of $3.4 million, or 121.4%. The increase was due to PhoenixOp’s first full year period of full-time operations. PhoenixOp began its drilling and completion activities in September 2023 and operations continually grew throughout 2024.
Mineral and Non-operating Segment
Selling, general, and administrative expense for the mineral and non-operating segment was $14.4 million for the year ended December 31, 2024, as compared to $6.8 million for the same period in 2023, an increase of $7.6 million, or 111.8%. The increase was primarily due to higher allocated corporate overhead of $4.5 million and increased fees associated with land acquisition and title work of $2.8 million during the year ended December 31, 2024 as compared to the same period in the prior year. This was primarily associated with our increased activity in acquiring leasehold and mineral assets.
Securities Segment
Selling, general, and administrative expense for the securities segment was $8.6 million for the year ended December 31, 2024, as compared to $4.7 million for the same period in 2023, an increase of $3.9 million, or 83.0%. The increase was primarily due to increased legal costs associated with our securities offerings of $2.0 million, increased securities administration costs of $0.8 million, and increased allocated corporate overhead of $0.9 million.
Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $27.9 million for the year ended December 31, 2024, as compared to $12.7 million for the same period in 2023, an increase of $15.2 million, or 119.7%, primarily as a result of increased employee headcount, which increased from 118 employees at December 31, 2023 to 135 employees at December 31, 2024.
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Operating Segment
Payroll and payroll-related expense for the operating segment was $8.6 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $5.4 million, or 168.8%, due to PhoenixOp’s first full year period of full time operations.
Mineral and Non-operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $13.3 million for the year ended December 31, 2024, as compared to $6.4 million for the same period in 2023, an increase of $6.9 million, or 107.8%, due to increased activity in acquiring leasehold and mineral assets.
Securities Segment
Payroll and payroll-related expense for the securities segment was $6.1 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $2.9 million, or 90.6%, primarily due to the increased number of personnel engaged in the administration and management of our securities offerings.
Advertising and Marketing Expense
Advertising and marketing expense was $0.7 million for the year ended December 31, 2024, as compared to $4.1 million for the same period in 2023, a decrease of $3.4 million, or 82.9%. The decrease was primarily the result of spending $3.6 million on an audio marketing campaign in 2023 attributable to the securities segment that did not recur in 2024.
Loss on Sale of Assets
Loss on sale of assets was $0.6 million for the year ended December 31, 2024 as a result of the disposition of certain mineral interests in the Williston basin within the mineral and non-operating segment, with no comparable activity in the prior-year period.
Impairment Expense
Impairment expense was $0.6 million for the year ended December 31, 2024, as compared to $1.0 million for the same period in 2023, a decrease of $0.4 million, or 40.0%. In 2024, impairment expense was a result of write-offs associated with title defects and lease expirations within the mineral and non-operating segment, whereas impairment expense in 2023 was attributable to a decrease in natural gas prices and the resulting impairment of the carrying value of our proved natural gas properties within the mineral and non-operating segment.
Other Expenses
Interest Expense, Net
Interest expense was $90.2 million for the year ended December 31, 2024, as compared to $47.9 million for the same period in 2023, an increase of $42.3 million, or 88.3%. The increase was primarily due to increased sales of our unregistered debt securities, which increased from $421.8 million outstanding at December 31, 2023 to $737.9 million outstanding at December 31, 2024, with no significant changes in interest rates between the periods, and a $2.9 million increase in amortized debt discount and debt issuance costs for the year ended December 31, 2024 as compared to the prior-year period.
Loss on Derivatives
Loss on derivatives was $6.0 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023. The increase was primarily a result of unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024, with limited comparable activity for the same period in 2023.
Loss on Debt Extinguishments
Loss on debt extinguishments was $1.7 million for the year ended December 31, 2024, as compared to $0.3 million for the same period in 2023, an increase of $1.4 million, or 466.7%. The increase was primarily due to increased write-offs of debt issuance costs associated with the early redemptions of bonds issued pursuant to
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Regulation A and Regulation D, of which $17.7 million of bonds were redeemed during the year ended December 31, 2024, as compared to $4.3 million of bonds redeemed for the same period in 2023.
The following table summarizes the par value of bonds redeemed for the periods indicated:
|
|
Year Ended December 31, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2024 |
|
|
2023 |
|
|
$ |
|
|
% |
|
||||
Reg D Bonds |
|
|
|
|
|
|
|
|
|
|
|
|
||||
August 2023 506(c) Bonds |
|
$ |
12,426 |
|
|
$ |
265 |
|
|
$ |
12,161 |
|
|
|
4,589.1 |
% |
Senior Reg D Bonds |
|
|
100 |
|
|
|
915 |
|
|
|
(815 |
) |
|
|
(89.1 |
%) |
December 2022 506(c) Bonds |
|
|
1,592 |
|
|
|
1,004 |
|
|
|
588 |
|
|
|
58.6 |
% |
Total Reg D Bonds |
|
|
14,118 |
|
|
|
2,184 |
|
|
|
11,934 |
|
|
|
546.4 |
% |
Reg A Bonds |
|
|
2,306 |
|
|
|
2,122 |
|
|
|
184 |
|
|
|
8.7 |
% |
Adamantium Bonds |
|
|
1,319 |
|
|
|
— |
|
|
|
1,319 |
|
|
NM |
|
|
Total |
|
$ |
17,743 |
|
|
$ |
4,306 |
|
|
$ |
13,437 |
|
|
|
312.1 |
% |
NM – not meaningful.
Non-GAAP Financial Measures
Our management uses EBITDA to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. By providing this non-GAAP financial measure, together with a reconciliation to GAAP results, we believe we are enhancing investors’ understanding of our business and our operating performance, as well as assisting investors in evaluating how well we are executing strategic initiatives.
EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income (loss), the most directly comparable GAAP measure. In particular, EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, and amortization expense, which have been necessary elements of our expenses. Because EBITDA does not account for these expenses, its utility as a measure of our operating performance has material limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our consolidated financial statements and the related notes included elsewhere in this Annual Report.
The following table shows a reconciliation of EBITDA to net income (loss), the most comparable GAAP measure, as presented on the consolidated statements of operations for the periods presented:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Net income (loss) |
|
$ |
66,108 |
|
|
$ |
(24,793 |
) |
|
$ |
(16,189 |
) |
Interest income |
|
|
(1,653 |
) |
|
|
(705 |
) |
|
|
(66 |
) |
Interest expense, net |
|
|
161,214 |
|
|
|
90,210 |
|
|
|
47,882 |
|
Depreciation, depletion, and amortization |
|
|
177,913 |
|
|
|
85,977 |
|
|
|
34,228 |
|
EBITDA |
|
$ |
403,582 |
|
|
$ |
150,689 |
|
|
$ |
65,855 |
|
EBITDA was $403.6 million for the year ended December 31, 2025 as compared to $150.7 million for the year ended December 31, 2024, an increase of $252.9 million, or 167.8%. The increase in EBITDA was primarily driven by a $406.0 million increase in consolidated revenues and a $58.8 million increase in gain on derivatives, primarily as a result of favorable changes in the mark-to-market value of commodity derivatives entered into during the year ended December 31, 2025, partially offset by a $210.8 million increase in operating expense (excluding depreciation, depletion, and amortization expense), primarily driven by purchased crude oil expenses, increased cost of sales, and increased payroll and payroll-related expenses.
EBITDA was $150.7 million for the year ended December 31, 2024, as compared to $65.9 million for the same period in 2023, an increase of $84.8 million, or 128.7%. The increase in EBITDA was primarily driven by a $163.1
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million increase in consolidated revenues, partially offset by a $71.0 million increase in operating expense (excluding depreciation, depletion, and amortization expense), primarily driven by increased cost of sales, increased legal, accounting and land-related professional service fees and other corporate overhead costs, and a $6.0 million increase in loss on derivatives primarily due to unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024.
Assuming commodity prices consistent with our planning assumptions, we expect our EBITDA to grow substantially in 2026 as the capital raised and deployed by us is expected to produce meaningful revenues. In 2025, the majority of revenues were produced from our properties acquired in 2024. Our management expects that the $592.2 million raised during the year ended December 31, 2025, and the corresponding investments in properties acquired and, in the case of properties and cash contributed to PhoenixOp, developed through the year ended December 31, 2025, will continue producing substantial revenues in 2026.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity to date have been cash flows from operations, borrowings under credit facilities, issuances of debt securities, and the issuance of the Series A Preferred Shares in September 2025. Future sources of liquidity may also include other credit facilities, continued issuances of debt or equity securities, which may be different than the type of debt or equity securities we have issued so far in terms of security, maturity, and interest rates, asset-backed or other securitizations, and capital contributions. Our primary uses of cash are on the development and operation of PhoenixOp’s properties, the acquisition of mineral and royalty interests, lease operating expenses, and our proportionate share of production and ad valorem taxes for mineral and royalty interests, production costs, including gathering, processing, and transportation costs, debt service payments and distributions on the Series A Preferred Shares, the reduction of outstanding debt balances, and general overhead and other corporate expenses. As we continue to engage in increased drilling and direct production activities through PhoenixOp, we expect the development and operation of PhoenixOp’s properties to become an increasingly significant use of our cash. As of December 31, 2025, we had cash and cash equivalents of $65.8 million, outstanding indebtedness of $1,529.9 million, and a liquidation preference of Series A Preferred Shares of $67.6 million.
As of December 31, 2025, we had $147.9 million of debt coming due and $128.6 million of interest payable within the next 12 months, as well as $1.7 million of distributions payable on the Series A Preferred Shares. Over the next 12 months, we expect to drill between 88 to 113 gross and 54.0 to 70.0 net wells across our operated leasehold acreage in the Bakken/Williston Basin in North Dakota and Montana, and expect to participate in the drilling of between 224 to 304 gross and 13.9 to 18.8 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $830.0 million and $890.0 million of capital expenditures over the next 12 months.
Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, making distributions on the Series A Preferred Shares, or refinancing our indebtedness, will depend on our ability to generate cash in the future. We raised $592.2 million in proceeds from the issuance of debt securities and increased borrowings under the Fortress Credit Agreement and $47.9 million, net of offering costs, from the Series A Preferred Shares offering during the year ended December 31, 2025. We believe that these sources of liquidity will be sufficient to meet our cash requirements, with respect to our current commitments, including normal operating needs, debt service obligations, and capital expenditures, for at least the next 12 months, and will allow us to continue to execute on our strategy of expanding our direct drilling operations through PhoenixOp and acquiring attractive mineral and royalty interests in order to position us to grow our cash flows. Although we expect that our cash flows from operations will be sufficient to meet our fixed obligations, to fully realize our business plan we anticipate that we would need to raise approximately $459.6 million in capital in 2026, which may involve different types of financing or issuances of debt or equity securities that differ from the types of securities we have previously issued.
We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather, and general economic, financial, competitive, legislative, regulatory, and other factors. We are currently monitoring our operations and industry developments, including our drilling operations and production plans, in light of recent changes in the commodity price environment and industry volatility. Although oil prices have surged recently following the onset of the conflict
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in the Middle East involving Iran, Israel, the United States, and numerous other oil producing countries in the region, and the closure of the Strait of Hormuz, this follows weaker oil prices that persisted through much of the second half of 2025, when oil prices went from $70.00 per barrel as of July 30, 2025 to $55.27 per barrel as of December 16, 2025. These prices were below those assumed for purposes of our business plan. While we believe we are well-positioned to navigate a lower-price environment, in the event of a prolonged period of commodity prices below those assumed for purposes of our business plan, our cash flows from operations would decrease and we may determine to adjust our business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. Conversely, subject to commodity prices, operational conditions and capital availability, we may contemplate adding additional completion resources during the second quarter of 2026 in order to accelerate the timing of bringing certain wells online and increase production volumes, and may also evaluate the addition of a fourth drilling rig later in 2026. We may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. See “Risk Factors—Risks Related to Our Business and Operations—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.” If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities, or other means. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves. See “Risk Factors.”
We or our affiliates may from time to time seek to repurchase or retire Registered Notes, other indebtedness, or Series A Preferred Shares through cash purchases and/or exchanges for equity or debt securities, in open-market purchases, privately negotiated transactions, tender or exchange offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions, and other factors. The amounts involved may be material. For more information regarding the material terms of our outstanding indebtedness, see “—Indebtedness” below.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Net cash provided by (used in) |
|
|
|
|
|
|
|
|
|
|||
Operating activities |
|
$ |
301,086 |
|
|
$ |
101,174 |
|
|
$ |
(1,023 |
) |
Investing activities |
|
|
(843,498 |
) |
|
|
(437,703 |
) |
|
|
(278,661 |
) |
Financing activities |
|
|
487,389 |
|
|
|
451,915 |
|
|
|
280,505 |
|
Net increase (decrease) in cash and cash equivalents |
|
$ |
(55,023 |
) |
|
$ |
115,386 |
|
|
$ |
821 |
|
Operating Activities
Net cash provided by operating activities for the year ended December 31, 2025 was $301.1 million, as compared to $101.2 million for the same period in 2024, an increase of $199.9 million in cash provided by operating activities. The increase was primarily due to a $90.9 million increase in net income, adjusted for non-cash charges of $48.5 million, and net favorable fluctuations of $60.5 million from changes in operating assets and liabilities. The $60.5 million cash inflow from changes in operating assets and liabilities was primarily due to increased other current liabilities, accounts payable, accrued interest, other operating activities, and earnest payments totaling $134.2 million, partially offset by decreased accounts receivable of $51.9 million and decreased escrow account liability of $20.7 million, primarily due to the timing of cash receipts and payments during the year ended December 31, 2025 as compared to the same period in 2024.
Net cash provided by operating activities for the year ended December 31, 2024 was $101.2 million, as compared to $1.0 million used in operations for the same period in 2023, an increase of $102.2 million in cash provided by operating activities. The increase was primarily due to an $8.6 million increase in net loss, adjusted for non-cash charges of $63.8 million, and net favorable fluctuations of $47.0 million from changes in operating assets and liabilities. The $47.0 million cash inflow from changes in operating assets and liabilities was primarily due to a net increase of $29.2 million in accounts receivable, accounts payable, accrued expenses and other current liabilities,
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primarily due to the timing of cash receipts and payments, and an $18.2 million increase in accrued interest from the increased amount of debt securities issued during the year ended December 31, 2024 as compared to the same period in 2023.
Investing Activities
Net cash used in investing activities for the year ended December 31, 2025 was $843.5 million, as compared to $437.7 million for the same period in 2024, an increase of $405.8 million in cash used in investing activities. The increase was primarily driven by a $397.1 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment, $2.5 million of additions to other property and equipment during the year ended December 31, 2025 that did not occur in the prior-year period, and $6.2 million of proceeds received in connection with the disposition of mineral interests during the year ended December 31, 2024 that did not recur in the current-year period.
Net cash used in investing activities for the year ended December 31, 2024 was $437.7 million, as compared to $278.7 million for the same period in 2023, an increase of $159.0 million in cash used in investing activities. The increase was primarily driven by a $165.3 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment during the year ended December 31, 2024, with limited operations for the same period in 2023, and $6.2 million of proceeds received in connection with the disposition of mineral interests during the year ended December 31, 2024 that did not occur in the prior-year period.
Financing Activities
Net cash provided by financing activities for the year ended December 31, 2025 was $487.4 million, as compared to $451.9 million for the same period in 2024, an increase of $35.5 million in cash provided by financing activities. The increase was primarily driven by proceeds from the Series A Preferred Shares offering that closed in September 2025 totaling $47.9 million, net of offering costs, a $29.0 million decrease in repayments of debt, primarily due to the repayment of merchant cash advances and a line of credit in 2024 that were not applicable in 2025, a $4.8 million decrease in member’s distributions, and a $4.3 million decrease in payments of deferred closings associated with mineral interest acquisitions, partially offset by decreased proceeds from issuances of debt, net of debt discount, of $29.2 million, a $20.6 million increase in payments of debt issuance costs, a $0.3 million decrease in member’s contributions, and a $0.3 million increase in payments of dividends for the Series A Preferred Shares.
Net cash provided by financing activities for the year ended December 31, 2024 was $451.9 million, as compared to $280.5 million for the same period in 2023, an increase of $171.4 million in cash provided by financing activities. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $220.1 million and a $2.7 million decrease in members’ distributions, partially offset by a $19.7 million increase in repayments of debt, a $15.0 million increase in payments of debt issuance costs, a $9.8 million decrease in members’ contributions, and a $6.9 million increase in payments of deferred closings associated with mineral interest acquisitions.
Preferred Equity
In September 2025, we completed our offering of the Series A Preferred Shares, which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025. We sold an aggregate of 2,704,023 Series A Preferred Shares at closing, which represented $67.6 million in initial liquidation preference at a public offering price of $20.00 per share for gross proceeds of $54.1 million. Offering costs of $6.2 million were recorded as a reduction of the gross proceeds. In addition, at issuance we recorded a $2.4 million discount associated with the stepped distribution rate feature of the Series A Preferred Shares, which provides for increases in the distribution rate prior to the commencement of the 11.0% perpetual distribution rate in year five. This amount was recorded as an additional reduction to the carrying value of the Series A Preferred Shares and is being amortized as a deemed dividend through the date the perpetual distribution rate becomes effective. For the year ended December 31, 2025, $0.2 million of this discount was amortized.
Holders of the Series A Preferred Shares generally have no voting rights. However, if we do not pay distributions on the Series A Preferred Shares for six or more quarterly distribution periods (whether or not consecutive), the holders of the Series A Preferred Shares will be entitled to vote for the election of two additional directors to serve on the board of directors until we pay, or declare and set aside funds for the payment of, all distributions that we owe on the Series A Preferred Shares.
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The Series A Preferred Shares rank senior to all Junior Securities (including our common equity interests), pari passu with all Parity Securities, and junior to all Senior Securities, and are junior to all of our existing and future indebtedness and any indebtedness or equity securities or our subsidiaries. Holders of the Series A Preferred Shares are entitled to receive cumulative cash distributions based on the initial liquidation preference of $25.00 per share, accruing from the initial issuance date and, when, as, and if declared by our board of directors, payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year. The annual distribution rate is 10.0% for the period from the issuance date to, but excluding, October 15, 2028, 10.5% for the period from October 15, 2028 to, but excluding, October 15, 2029, and 11.0% from and including October 15, 2029. During the year ended December 31, 2025, the Company paid $0.3 million of distributions to the holders of the Series A Preferred, equal to $0.1111 per share. In December 2025, the board of directors authorized and declared a distribution on the Series A Preferred Shares equal to $0.6250 per share, which was paid on January 15, 2026 to holders of record as of January 2, 2026 and totaled $1.7 million. As of December 31, 2025, the Company had accrued $1.5 million of dividends payable, which is included in other current liabilities on the consolidated balance sheet.
In the event of our voluntary or involuntary liquidation, dissolution, or winding up, the holders of the Series A Preferred Shares will generally have the right to receive the initial liquidation preference of $25.00 per Series A Preferred Share, plus any accumulated and unpaid distributions. The Series A Preferred Shares are not redeemable at the option of the holders. The Series A Preferred Shares are, however, redeemable at our option, in whole or in part, at a cash redemption price of $27.50 per share, plus any accumulated and unpaid distributions. The Series A Preferred Shares are not convertible or exchangeable for any of our securities or property.
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Indebtedness
Set forth below is a chart of our outstanding third-party indebtedness as of December 31, 2025 (dollars in thousands):
Indebtedness |
|
Offering |
|
Principal |
|
|
Term |
|
Earliest |
|
|
Latest |
|
Interest |
|
|||
Secured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Fortress Credit Agreement(1) |
|
N/A |
|
$ |
450,000 |
|
|
3 years |
|
|
— |
|
|
10/27/2028 |
|
Term SOFR + 7.10% |
|
|
Adamantium Secured Notes(2) |
|
N/A |
|
|
8,600 |
|
|
7 years |
|
11/1/2031 |
|
|
10/10/2032 |
|
|
16.5 |
% |
|
Unsecured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Reg A Bonds(3) |
|
12/23/2021 |
|
|
50,166 |
|
|
3 years |
|
1/10/2026 |
|
|
08/10/2027 |
|
|
9.0 |
% |
|
Senior Reg D Bonds(4) |
|
7/20/2022 |
|
|
7,804 |
|
|
5 years |
|
7/31/2027 |
|
|
12/31/2027 |
|
|
11.0 |
% |
|
December 2022 506(c) Bonds(5): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Series B |
|
12/22/2022 |
|
|
14,191 |
|
|
3 years |
|
1/10/2026 |
|
|
10/10/2026 |
|
|
10.0 |
% |
|
Series C |
|
12/22/2022 |
|
|
9,060 |
|
|
5 years |
|
12/10/2027 |
|
|
9/10/2028 |
|
|
11.0 |
% |
|
Series D |
|
12/22/2022 |
|
|
35,858 |
|
|
7 years |
|
12/10/2029 |
|
|
10/10/2030 |
|
|
12.0 |
% |
|
August 2023 506(c) Bonds(5): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Series U, AA, and FF |
|
8/29/2023 |
|
|
92,711 |
|
|
1 year |
|
1/10/2026 |
|
|
12/10/2026 |
|
9.0% - 10.0% |
|
||
Series V, BB, and GG |
|
8/29/2023 |
|
|
106,893 |
|
|
3 years |
|
8/10/2026 |
|
|
01/10/2029 |
|
10.0% - 11.0% |
|
||
Series W, CC, and HH |
|
8/29/2023 |
|
|
70,289 |
|
|
5 years |
|
8/10/2028 |
|
|
12/10/2030 |
|
11.0% - 12.0% |
|
||
Series X, DD, and II |
|
8/29/2023 |
|
|
85,210 |
|
|
7 years |
|
9/10/2030 |
|
|
12/10/2032 |
|
12.0% - 13.0% |
|
||
Series Y |
|
8/29/2023 |
|
|
3,604 |
|
|
9 years |
|
9/10/2032 |
|
|
9/10/2033 |
|
|
12.5 |
% |
|
Series Z, EE, and JJ |
|
8/29/2023 |
|
|
285,077 |
|
|
11 years |
|
9/10/2034 |
|
|
12/10/2036 |
|
13.0% - 14.0% |
|
||
Total Reg D/Reg A Bonds |
|
|
|
|
760,863 |
|
|
|
|
|
|
|
|
|
|
|
||
Exchange Notes(3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Three-Year Exchange Notes |
|
5/15/2025 |
|
|
3,902 |
|
|
3 years |
|
12/10/2027 |
|
|
12/10/2028 |
|
|
9.0 |
% |
|
Five-Year Exchange Notes |
|
5/15/2025 |
|
|
7,400 |
|
|
5 years |
|
12/10/2029 |
|
|
12/10/2030 |
|
|
10.0 |
% |
|
Seven-Year Exchange Notes |
|
5/15/2025 |
|
|
4,111 |
|
|
7 years |
|
12/10/2031 |
|
|
12/10/2032 |
|
|
11.0 |
% |
|
Eleven-Year Exchange Notes |
|
5/15/2025 |
|
|
15,604 |
|
|
11 years |
|
5/10/2036 |
|
|
12/10/2036 |
|
|
12.0 |
% |
|
Total Exchange Notes |
|
|
|
|
31,017 |
|
|
|
|
|
|
|
|
|
|
|
||
Registered Notes(6): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Three-Year Registered Notes |
|
5/14/2025 |
|
|
9,737 |
|
|
3 years |
|
5/10/2028 |
|
|
12/10/2028 |
|
|
9.0 |
% |
|
Five-Year Registered Notes |
|
5/14/2025 |
|
|
6,358 |
|
|
5 years |
|
5/10/2030 |
|
|
12/10/2030 |
|
|
10.0 |
% |
|
Seven-Year Registered Notes |
|
5/14/2025 |
|
|
3,487 |
|
|
7 years |
|
5/10/2032 |
|
|
12/10/2032 |
|
|
11.0 |
% |
|
Eleven-Year Registered Notes |
|
5/14/2025 |
|
|
15,097 |
|
|
11 years |
|
5/10/2036 |
|
|
12/10/2036 |
|
|
12.0 |
% |
|
Total Registered Notes |
|
|
|
|
34,679 |
|
|
|
|
|
|
|
|
|
|
|
||
Adamantium Bonds(7) |
|
9/29/2023 |
|
|
244,731 |
|
|
5-11 years |
|
1/10/2029 |
|
|
12/10/2036 |
|
13.0% - 16.0% |
|
||
Total Unsecured Debt |
|
|
|
|
1,071,290 |
|
|
|
|
|
|
|
|
|
|
|
||
Total Debt |
|
|
|
$ |
1,529,890 |
|
|
|
|
|
|
|
|
|
|
|
||
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Table of Contents
Fortress Credit Agreement
We entered into the Fortress Credit Agreement with Fortress on August 12, 2024, which provides for a $100.0 million term loan facility (the “Fortress Term Loan”) that was borrowed in full on August 12, 2024, and a $35.0 million delayed draw term loan facility that was borrowed in full on October 11, 2024 (any loans thereunder, together with the Fortress Term Loan, the “Fortress Tranche A Loan”). On December 18, 2024, the Fortress Credit Agreement was amended to, among other things, provide for a new tranche of term loans (the “Fortress Tranche C Loan”) in an aggregate principal amount of $115.0 million that was borrowed in full on December 18, 2024. On April 16, 2025, the Fortress Credit Agreement was further amended to, among other things, establish a new tranche of term loans (the “Fortress Tranche D Loan”) in an aggregate principal amount of $50.0 million, with $25.0 million aggregate principal amount borrowed on April 16, 2025 and $25.0 million aggregate principal amount borrowed on May 9, 2025. Then, on August 1, 2025, the Fortress Credit Agreement was amended further to provide for a new tranche of term loans (the “Fortress Tranche E Loan”) in an aggregate principal amount of $100.0 million that was borrowed in full on August 1, 2025.
On October 27, 2025, the Fortress Credit Agreement was further amended to provide for a new tranche of term loans available on a discretionary basis in an aggregate principal amount of $350.0 million (the “Tranche G Commitments”), of which $50.0 million in aggregate principal amount was borrowed on October 27, 2025 (the “Amendment No. 7 Term Loan”), subsequently reducing the amount available under the Tranche G Commitments to $300.0 million.
On February 12, 2026, the Fortress Credit Agreement was further amended to provide a new $75.0 million facility (together with the Fortress Tranche A Loan, the Fortress Tranche C Loan, the Fortress Tranche D Loan, the Fortress Tranche E Loan, and the Amendment No. 7 Term Loan, the “Fortress Loans”), which was borrowed in full on February 12, 2026, subsequently reducing the amount available under the Tranche G Commitments to $225.0 million.
The Fortress Credit Agreement also provides for a $8.5 million tranche of loans (the "Fortress Tranche B Loan") and a $6.5 million tranche of loans (the “Fortress Tranche F Loan”), which represents contingent principal obligations that are only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Credit Agreement or a bankruptcy filing by the Credit Parties.
Obligations under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Equity and its subsidiaries that have guaranteed our obligations under the Fortress Credit Agreement, subject to certain
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Table of Contents
exceptions. Furthermore, as of August 12, 2024, in connection with the Fortress Credit Agreement, the lenders under the Fortress Credit Agreement purchased and assumed all outstanding extensions of credit made by ANB under the ANB Credit Agreement. As a result, the ANB Credit Agreement and all related documentation were terminated and are no longer in effect.
The Fortress Loans are subject to 3.00% of original issue discount (“OID”). The $8.5 million and $6.5 million of OID issued in connection with the Fortress Tranche B Loan and Fortress Tranche F Loan are to be rebated if certain conditions are met, and therefore represent contingent principal obligations that are only due and payable (together with accrued interest) upon the occurrence of those conditions, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing. We expect the OIDs associated with the Fortress Rebate Loans will be rebated in full.
Borrowings under the Fortress Credit Agreement bear interest at a rate per annum equal to Term SOFR (as defined in the Fortress Credit Agreement) plus 0.1% plus 7.0%. Interest on the Fortress Loans is payable quarterly in arrears. The outstanding principal amount of the Fortress Loans (including, if applicable, the Fortress Tranche B Loan and the Fortress Tranche F Loan) must be repaid as follows: (i) on October 31, 2027, $262.5 million of the outstanding principal amount of the Fortress Loans less the aggregate amount of all voluntary prepayments and mandatory prepayments made as of October 31, 2027; and (ii) the remaining aggregate outstanding principal amount on October 27, 2028. In connection with any payment in full of the Fortress Loans (whether by voluntary prepayment or acceleration or on the maturity date), PhoenixOp will pay a repayment premium in an amount sufficient to achieve a MOIC (as defined in the Fortress Credit Agreement) of (i) for the Tranche G Commitments, 1.12, and (ii) for the remaining Fortress Loans, calculated separately with respect to each tranche, 1.18.
The Fortress Credit Agreement contains various customary affirmative and negative covenants, as well as financial covenants. The Fortress Credit Agreement requires us to maintain (a) a maximum total secured leverage ratio (i) as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024), (ii) as of the last day of any fiscal quarter during the period from March 31, 2026 through September 30, 2026 of less than or equal to 1.85 to 1.00, and (iii) as of the last day of any fiscal quarter ending on or after December 31, 2026 of less than 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through March 31, 2026, (iii) 0.90 to 1.00 from April 30, 2026 through December 31, 2026, and (iv) 1.00 to 1.00 for each calendar month ending thereafter, and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter (i) ending during the period from June 30, 2024 through December 31, 2024 of at least 2.00 to 1.00, (ii) ending during the period from March 31, 2025 through December 31, 2025 of at least 1.70 to 1.00, (iii) ending during the period from March 31, 2026 through June 30, 2026 of at least 1.50 to 1.00, (iv) ending during the period from September 30, 2026 through December 31, 2026, of at least 1.70 to 1.00, and (v) ending during the period from March 31, 2027 and thereafter of at least 2.00 to 1.00. The Fortress Credit Agreement also places certain limits on our ability to incur additional indebtedness, including the issuance of unsecured notes or bonds and accounts receivable factoring arrangements, as well as limits on our ability to redeem the Series A Preferred Shares. Under the terms of the Fortress Credit Agreement, we may only expend an aggregate amount of $5,000,000 to redeem Series A Preferred Shares in any fiscal quarter, which quarterly limit may be reduced by the amount of certain cash payments made during such quarter to the extent related to certain debt refinancing transactions. On February 12, 2026, subsequent to the balance sheet date, we executed an amendment of the Fortress Credit Agreement, which provided waivers of compliance with the covenants on (i) our total secured leverage ratio as of December 31, 2025, (ii) our current ratio during the period from November 30, 2025 through January 31, 2026, and (iii) our asset coverage ratio as of December 31, 2025.
The Fortress Credit Agreement contains customary events of default, including, but not limited to, nonpayment of the Fortress Loans and any other material indebtedness, material inaccuracies of representations and warranties, violations of covenants, certain bankruptcies and liquidations, certain material judgments, and certain events related to the security documents.
As described above, a portion of the proceeds from the Fortress Term Loan was used to pay all amounts owed under the ANB Credit Agreement. We will use the remaining proceeds of the Fortress Loans to finance the development of oil and gas properties in accordance with the approved plan of development as provided in the Fortress Credit Agreement.
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Table of Contents
Adamantium Debt
Adamantium was formed on June 21, 2023 as our wholly-owned financing subsidiary for the purpose of undertaking financing efforts under Regulation D and subsequently loaning amounts to us and/or our subsidiaries, as needed. Adamantium offers high net worth individuals Bonds pursuant to an offering under Rule 506(c) of Regulation D that commenced in September 2023, and does not expect to undertake financing efforts under Regulation A. Adamantium has in the past, and may in the future, issue debt securities in other offerings exempt from registration under the Securities Act under Section 4(a)(2) thereof or any other available exemption, including, for example, the Adamantium Secured Note.
On September 14, 2023, we, as borrower, entered into the Adamantium Loan Agreement with Adamantium, as lender. On October 30, 2023, we, Adamantium, and PhoenixOp entered into an amendment to the Adamantium Loan Agreement to add PhoenixOp as a borrower, and on November 1, 2024, January 24, 2025, October 6, 2025, February 12, 2026, and March 16, 2026, entered into five subsequent amendments to increase the loan amount thereunder. As amended, the Adamantium Loan Agreement provides for up to $609.3 million in aggregate principal amount of borrowings in one or more advances, comprising $600.0 million from the proceeds of Adamantium Bonds and $9.3 million from the proceeds of the Adamantium Secured Note. Adamantium may, but is not guaranteed to, issue $600.0 million in aggregate principal amount of Adamantium Bonds to fund advances to us and PhoenixOp pursuant to the Adamantium Loan Agreement. The timing of any advance under the Adamantium Loan Agreement is contingent upon Adamantium’s receipt of proceeds from the sale of Adamantium Securities. Each advance will have a maturity and interest rate that matches the terms of the respective Adamantium Securities sold prior to such advance and to which such advance relates. We expect to use the proceeds of borrowings under the Adamantium Loan Agreement (i) to purchase mineral rights and non-operated working interests, as well as additional asset acquisitions, (ii) to finance potential drilling and exploration operations of one or more subsidiaries (including PhoenixOp), and (iii) for other working capital needs.
As of December 31, 2025, $244.7 million aggregate principal amount of Adamantium Bonds was outstanding, with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% - 16.0% per annum, and $8.6 million aggregate principal amount was outstanding under the Adamantium Secured Note, which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement, and, in each case, the corollary amount of borrowings was outstanding under the Adamantium Loan Agreement.
The Adamantium Securities contain customary events of default and may be redeemed at the option of Adamantium at any time without premium or penalty. The holders of Adamantium Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10.0% of the then-outstanding principal amount of Adamantium Bonds in any given calendar year. The holder of the Adamantium Secured Note has the right to request redemption of its note at par, subject to a limit of $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period.
Amounts loaned under the Adamantium Loan Agreement are secured by mortgages on certain of our properties, which mortgages are junior to the security interest under the Fortress Credit Agreement and other existing and future senior secured indebtedness. The aggregate outstanding amount of all advances under the Adamantium Loan Agreement may not exceed 100.0% of the aggregate total discounted present value of the junior mortgages serving as collateral thereunder, after deducting any allocable amount securing any of our outstanding senior indebtedness (the “Adamantium Loan-to-Value Ratio”). The value of such collateral will be determined by one or more reserve studies performed by a third party retained by us on an annual basis. In the event the aggregate amount outstanding under the Adamantium Loan Agreement exceeds the Adamantium Loan-to-Value Ratio, we may cure such deficiency by either pledging additional collateral or repaying a portion of the borrowings under the Adamantium Loan Agreement until the Adamantium Loan-to-Value Ratio is achieved.
At the option of Adamantium, an advance may be made on either (i) a current basis, whereby we make interest-only monthly payments in cash to Adamantium on the tenth day of each month, or (ii) an accrual basis, whereby interest is compounded monthly and we will pay all accrued and unpaid interest at maturity of the respective advance. Interest will accrue a full pro rata portion of the annual rate of interest for each calendar month regardless of the number of days an advance is outstanding during such calendar month, on the same terms as the interest payable on the Adamantium Securities sold prior to such advance and to which such advance relates. On each respective maturity date for advances made on both a current and accrual basis, the outstanding principal amount, together with all accrued and unpaid interest thereon, will mature and be due and payable to Adamantium. To the extent the Adamantium
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Securities are accelerated or prepaid, in whole or in part, we will be obligated to pay or prepay, in whole or in part, all or any part of any outstanding indebtedness under the Adamantium Loan Agreement so as to satisfy the obligations and terms of the accelerated or prepaid Adamantium Securities. Adamantium will use any amounts repaid under the Adamantium Loan Agreement to repay the corresponding Adamantium Securities. The Adamantium Loan Agreement is not a revolving facility and we may not reborrow amounts repaid.
The Adamantium Loan Agreement can be amended or waived with the consent of the Company and Adamantium, including in order to change the amount, rate, payment terms, collateral package, and borrowers thereunder. The consent of holders of our other debt securities is not required for any amendment or waiver of the Adamantium Loan Agreement, and any such amendment or waiver may be adverse to the interests of such holders. Because Adamantium is our wholly-owned financing subsidiary with common management, there exists the potential for conflicts of interest with respect to decisions regarding the Adamantium Loan Agreement, including with respect to waivers and amendments thereto. Management is committed to fulfilling its fiduciary duties and operating in good faith.
Registered Notes
In May 2025, the SEC declared effective our registration statement with respect to the continuous offering of up to $750.0 million aggregate principal amount of our Registered Notes with maturity dates ranging from three to eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum. As of December 31, 2025, we issued $34.8 million aggregate principal amount of Registered Notes.
The Registered Notes are contractually senior to the Subordinated Regulation D Bonds and contractually subordinated to obligations under the Fortress Credit Agreement, the Adamantium Debt, and the Senior Phoenix Bonds. The Registered Notes contain customary events of default and may be redeemed at our option at any time without premium or penalty. The holders of Registered Notes have a right to request redemption of their notes in certain circumstances at a discount to par, subject to a limit of 10.0% of the then-outstanding principal amount of the Registered Notes in any given calendar year.
Reg D/Reg A Bonds and Exchange Notes
As of December 31, 2025, we had $760.9 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D, Regulation A, and Section 3(a)(9) and/or 4(a)(2) of the Securities Act (other
than the Adamantium Bonds), consisting of:
(a) $7.8 million aggregate principal amount outstanding of Senior Reg D Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum, and which are pari passu with the Reg A Bonds and the Exchange Notes, are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Debt, and are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes;
(b) $702.9 million aggregate principal amount outstanding of Subordinated Reg D Bonds, which are contractually subordinated to obligations under the Fortress Credit Agreement, the Adamantium Debt, the Reg A Bonds, the Exchange Notes, the Senior Reg D Bonds, and the Registered Notes, comprising:
(i) $59.1 million aggregate principal amount outstanding of Series AAA through Series D-1 December 2022 506(c) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from three to seven years from the issue date and interest rates ranging from 10.0% to 12.0% per annum; and
(ii) $643.8 million aggregate principal amount outstanding of Series U through Series JJ-1 August 2023 506(c) Bonds, which are unsecured bonds offered and sold to date pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum;
(c) $50.2 million aggregate principal amount outstanding of Reg A Bonds, which are unsecured bonds offered and sold pursuant to an offering under Regulation A, which commenced in December 2021 and terminated in December 2024, with a term of three years from the issue date and an interest rate of 9.0% per annum, which Reg A Bonds are pari passu with the Senior Reg D Bonds and Exchange Notes and are contractually senior to obligations
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under the Subordinated Reg D Bonds and the Registered Notes; and
(d) $31.0 million aggregate principal amount outstanding of Exchange Notes, which are unsecured bonds issued by us to holders of the Reg A Bonds in exchange for their Reg A Bonds in offerings exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act, with maturity dates of three, five, seven, or eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum, which Exchange Notes are pari passu with the Senior Reg D Bonds and Reg A Bonds, are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes, and are contractually subordinated to obligations under the Fortress Credit Agreement and the Adamantium Debt.
In March 2026, we approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $1.5 billion to $2.0 billion.
The Reg D/Reg A Bonds and Exchange Notes contain customary events of default. The Reg D/Reg A Bonds and Exchange Notes may be redeemed at our option at any time without premium or penalty. We will also be obligated to offer to holders of Reg A Bonds the right to have their Reg A Bonds repurchased upon a change of control (as described in the indenture governing the Reg A Bonds). The holders of Reg D/Reg A Bonds and Exchange Notes (other than the Senior Reg D Bonds) also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10.0% of the then-outstanding principal amount of the applicable series in any given calendar year.
Contractual Obligations and Commitments
A summary of our contractual obligations, commitments, and other liabilities as of December 31, 2025 is presented below:
(in thousands) |
|
2026 |
|
|
2027-2028 |
|
|
2029-2030 |
|
|
Thereafter |
|
|
Total |
|
|||||
Debt obligations(1) |
|
$ |
147,990 |
|
|
$ |
600,252 |
|
|
$ |
164,040 |
|
|
$ |
617,608 |
|
|
$ |
1,529,890 |
|
Interest payable(2) |
|
|
128,587 |
|
|
|
154,043 |
|
|
|
181,933 |
|
|
|
1,073,181 |
|
|
|
1,537,744 |
|
Operating lease obligations(3) |
|
|
2,362 |
|
|
|
4,822 |
|
|
|
4,209 |
|
|
|
4,203 |
|
|
|
15,596 |
|
Deferred closing arrangements(4) |
|
|
9,974 |
|
|
|
3,315 |
|
|
|
— |
|
|
|
— |
|
|
|
13,289 |
|
Generator obligations(5) |
|
|
9,588 |
|
|
|
2,019 |
|
|
|
— |
|
|
|
— |
|
|
|
11,607 |
|
Natural gas processing obligations(5) |
|
|
2,616 |
|
|
|
3,712 |
|
|
|
— |
|
|
|
— |
|
|
|
6,328 |
|
Drilling rig obligations(5) |
|
|
2,646 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,646 |
|
Saltwater disposal pump obligations(5) |
|
|
2,269 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,269 |
|
Total |
|
$ |
306,032 |
|
|
$ |
768,163 |
|
|
$ |
350,182 |
|
|
$ |
1,694,992 |
|
|
$ |
3,119,369 |
|
Critical Accounting Policies and Use of Estimates
This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements in conformity with GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue, and expenses, and disclosures of contingent assets and liabilities, including with respect to quantities of oil, natural gas, and NGL reserves that are the basis for the calculations of depreciation, depletion, and amortization and determinations of impairment of oil and natural gas properties. Our significant accounting policies are described in Note 1, “Description of Business and Summary of Significant Accounting Policies,” of the accompanying consolidated financial statements included elsewhere in this Annual Report.
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Critical accounting policies are those that we consider to be the most important in portraying our financial condition and results of operations and also require the greatest amount of judgments by management, including requiring an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time the estimate is made, if different estimates reasonably could have been used, or if changes in the estimate that are reasonably possible could materially impact the financial statements. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Judgments or uncertainties regarding the application of these policies may result in materially different amounts being reported under different conditions or using different assumptions. There can be no assurance that actual results will not differ from those estimates and assumptions.
Furthermore, reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our consolidated financial statements.
Oil and Gas Properties
We account for crude oil, natural gas and NGL exploration and development activities using the successful efforts method of accounting. Under this method, costs to acquire, drill, and complete development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Exploration costs, including geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but expensed if the well is determined to be unsuccessful. All capitalized well costs and leasehold costs of proved properties are depleted on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to a geologic basin.
Impairment of Long-Lived Assets
We follow the provisions of Accounting Standards Codification 360, Property, Plant, and Equipment, which requires that long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows, or evaluation value using expected future prices of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. The valuation of unproved oil and gas properties is subjective and requires management to make estimates and assumptions that, with the passage of time, may prove to be materially different from actual results. The unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. Management considers (i) estimated potential reserves and future net revenues from an independent expert, (ii) its history in exploring the area, (iii) its future drilling plans per its capital drilling program prepared by its reservoir engineers and operations management, and (iv) other factors associated with the area. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made.
Revenue from Contracts with Customers
We recognize our revenues following ASC 606, Revenue from Contracts with Customers. Our revenues are predominantly derived from contracts for the sale of crude oil, natural gas and NGL. For crude oil, natural gas and NGL produced by PhoenixOp, each unit of production delivered is treated as a separate performance obligation that is satisfied at the point in time control of the product transfers to the customer. Revenue is measured as the amount we expect to receive in exchange for transferring commodities to the customer. Our commodity sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling
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price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as we control the operated production prior to its transfer to customers.
In circumstances where we are the non-operator or mineral rights owner, we derive revenue from our interests in the sale of oil and natural gas production and do not consider ourself to have control of the product, resulting in the recognition of revenues net of post-production expenses. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. Because of the timing lag between production, sales and receipt of statements from purchasers or operators, we record accrued revenue based on estimated production volumes and estimated commodity prices.
Effective April 2025, we began conducting marketing activities through our newly established subsidiary, Firebird Marketing. These activities include the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp, and the subsequent sale of the crude oil to customers. We concluded that we act as a principal in these transactions because we obtain control of the crude oil prior to transferring it to customers. Accordingly, revenues and associated purchase costs are recognized on a gross basis.
We, through Firebird Services, provide water disposal services to PhoenixOp and third parties with respect to oil and gas production from wells in which we are the operator. Pricing for such services represents a fixed rate fee based on the quantity of water volume processed. Intercompany charges associated with PhoenixOp’s net interests are eliminated in consolidation. Revenue related to third-party working interest owners is recognized over time as the services are performed.
Preferred Equity
We evaluated the Series A Preferred Shares under ASC 480, Distinguishing Liabilities from Equity, to determine the appropriate classification. The Series A Preferred Shares are not subject to any unconditional obligation to redeem for cash or other assets and do not contain redemption features that would require liability or temporary equity classification. Accordingly, they have been classified as permanent equity on our consolidated balance sheets. Distributions are accrued as contractually obligated and are paid quarterly in arrears, when, as and if declared by our board of directors. The discount associated with the increasing-rate distributions is amortized using the effective interest method over the period preceding the commencement of the perpetual distribution rate. The accretion is recorded as an imputed distribution, recognized through retained earnings, with a corresponding increase to the carrying amount of the preferred equity.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates or from counterparty and customer credit risk, each as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our instruments that are sensitive to market risk were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, natural gas, and NGL production of our E&P operators, including PhoenixOp, which affects our revenue from PhoenixOp and the royalty payments we receive from our other E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas, and NGL has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices that our E&P operators receive for oil, natural gas, and NGL production depend on many factors outside of their and our control, such as the strength of the global economy and global supply and demand for the commodities they produce.
To reduce the impact of fluctuations in oil, natural gas, and NGL prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, natural gas, and NGL production through various transactions that limit the risks of fluctuations of future prices. Additionally, we are required to hedge a portion of anticipated oil production pursuant to certain covenants under the Fortress Credit Agreement. As a part of our
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derivative contracts, as of December 31, 2025, over the next three years, we had nearly 11.6 million Bbl hedged at a weighted average strike price of $60.69 per Bbl, which would generate aggregate cash settlements of approximately $701.1 million over the same period, assuming a price of $0 per Bbl. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our net cash provided by operating activities. Future transactions may include additional price swaps, whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, or collars, whereby we would receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility.
By using derivative instruments to economically limit exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. See “—Counterparty and Customer Credit Risk” below.
The fair market value of our commodity derivative contracts was a net asset of $43.4 million as of December 31, 2025. Based upon our open commodity derivative positions at December 31, 2025, a hypothetical 10.0% increase in the NYMEX WTI price would decrease our net derivative asset position by $70.5 million, while a 10.0% decrease in the NYMEX WTI price would increase our net derivative asset position by $70.5 million.
A $1.00 per Bbl change in our realized oil price would have resulted in a $8.6 million, $4.2 million, and a $1.4 million change in our oil revenues for the years ended December 31, 2025, 2024, and 2023, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million, $0.1 million, and a $0.2 million change in our natural gas revenues for the years ended December 31, 2025, 2024, and 2023, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a $0.7 million, a less than $0.1 million change, and a $0.2 million change in our NGL revenues for the years ended December 31, 2025, 2024, and 2023, respectively. Revenues from oil sales contributed 95.0%, 93.2%, and 89.5%, revenues from natural gas sales contributed 1.2%, 2.0%, and 5.8%, and revenues from NGL sales contributed 2.2%, 3.9%, and 4.7% of our consolidated revenues for the years ended December 31, 2025, 2024, and 2023, respectively.
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the years ended December 31, 2025 and 2024 was 11.3% and 11.8%, respectively. Assuming no change in the amount of borrowings under the Fortress Credit Agreement outstanding, a hypothetical 100 basis point increase or decrease in the average interest rate under these borrowings would increase or decrease our interest expense on those borrowings on an annual basis by approximately $4.5 million. See “—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”
Counterparty and Customer Credit Risk
We often maintain cash balances in excess of the federally insured limits, which may subject us to concentrations of credit risk. We manage this risk by maintaining deposits with a financial institution that we believe to be creditworthy and by monitoring their financial condition on an ongoing basis.
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of such counterparties as we deem appropriate. We have determined that our counterparties have an acceptable credit risk for the size of derivative position placed; therefore, we do not require collateral or other security from our counterparties. Additionally, we use master netting arrangements to minimize credit risk exposure.
Our principal exposures to credit risk are through receivables generated by product sales from the delivery of commodities that we extract and deliver to purchasers and the production activities of our operators. For the year ended December 31, 2025, three purchasers of our commodities and twelve third-party E&P operators made up 54.8% and 14.7% of our consolidated revenue, respectively, as compared to one purchaser of our commodities and ten third-party E&P operators that made up 21.0% and 35.3% of our consolidated revenue, respectively, for the year ended December 31, 2024, and one third-party E&P operator that made up 11.0% of our consolidated revenue for the year ended December 31, 2023.
Similarly, as of December 31, 2025, we had concentrations in accounts receivable of 13.0% with one purchaser of our commodities and 13.0% with one third-party E&P operator, as compared to 17.0%, 15.0%, and 13.0% with
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three third-party E&P operators as of December 31, 2024, and 26.0% and 14.0% with two third-party E&P operators as of December 31, 2023. Although we are exposed to a concentration of credit risk due to our reliance on operators and purchasers of our commodities, we do not believe the loss of any single counterparty would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous participants. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our third-party E&P operators have stipulated that royalty owners must still be paid for oil, gas, and NGL extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators or purchasers into bankruptcy proceedings would materially affect our operating results.
Furthermore, as PhoenixOp increases the extent of its operations and generates revenue from the sale of crude oil and natural gas delivered to purchasers, we expect that our concentration of revenue and accounts receivable among a limited number of third-party E&P operators will decrease, and we will achieve greater control over the terms of the sales agreements entered into among PhoenixOp and the purchasers.
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Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm |
112 |
Consolidated Balance Sheets as of December 31, 2025 and 2024 |
114 |
Consolidated Statements of Operations for the Years Ended December 31, 2025, 2024, and 2023 |
115 |
Consolidated Statements of Changes in Equity (Deficit) for the Years Ended December 31, 2025, 2024, and 2023 |
116 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023 |
117 |
Notes to Consolidated Financial Statements |
118 |
111
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phoenix Energy One, LLC
Irvine, California
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Phoenix Energy One, LLC and subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of operations, changes in equity (deficit) and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes to the consolidated financial statements (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts and disclosures to which they relate.
Estimation and Valuation of Proven Reserves
The estimation and valuation of proven reserves is identified as a critical audit matter. The valuation of these reserves is highly subjective due to the complexities involved in estimating the reserves, and the significant judgment required in determining the valuation assumptions, such as future commodity prices, production rates, and capital expenditures. The estimation of volumes and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. The following are the primary procedures we performed to address this critical audit matter. We performed the following audit procedures in relation to the evaluation of proved reserves:
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We have served as the Company’s auditors since 2023.
/s/
March 17, 2026
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
(in thousands, except share amounts)
|
|
December 31, |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
ASSETS |
|
|
|
|
|
|
||
Current assets |
|
|
|
|
|
|
||
Cash and cash equivalents |
|
$ |
|
|
$ |
|
||
Accounts receivable |
|
|
|
|
|
|
||
Earnest payments |
|
|
|
|
|
|
||
Other current assets |
|
|
|
|
|
|
||
Total current assets |
|
|
|
|
|
|
||
Property, plant, and equipment |
|
|
|
|
|
|
||
Oil and gas properties |
|
|
|
|
|
|
||
Other property and equipment |
|
|
|
|
|
|
||
Less: accumulated depreciation, depletion, and amortization |
|
|
( |
) |
|
|
( |
) |
Total property, plant, and equipment, net |
|
|
|
|
|
|
||
Right-of-use assets, net |
|
|
|
|
|
|
||
Other noncurrent assets |
|
|
|
|
|
|
||
TOTAL ASSETS |
|
$ |
|
|
$ |
|
||
LIABILITIES AND EQUITY (DEFICIT) |
|
|
|
|
|
|
||
Current liabilities |
|
|
|
|
|
|
||
Accounts payable |
|
$ |
|
|
$ |
|
||
Accrued expenses |
|
|
|
|
|
|
||
Current portion of long-term debt |
|
|
|
|
|
|
||
Current portion of deferred closings |
|
|
|
|
|
|
||
Escrow account |
|
|
|
|
|
|
||
Current operating lease liabilities |
|
|
|
|
|
|
||
Other current liabilities |
|
|
|
|
|
|
||
Total current liabilities |
|
|
|
|
|
|
||
Long-term debt, net of current portion |
|
|
|
|
|
|
||
Accrued interest |
|
|
|
|
|
|
||
Deferred closings |
|
|
|
|
|
|
||
Operating lease liabilities |
|
|
|
|
|
|
||
Asset retirement obligations |
|
|
|
|
|
|
||
Other noncurrent liabilities |
|
|
|
|
|
|
||
Total liabilities |
|
|
|
|
|
|
||
|
|
|
|
|
|
|||
Equity (deficit) |
|
|
|
|
|
|
||
Series A Preferred Shares ( |
|
|
|
|
|
|
||
Common equity |
|
|
|
|
|
|
||
Retained earnings (accumulated deficit) |
|
|
|
|
|
( |
) |
|
Total equity (deficit) |
|
|
|
|
|
( |
) |
|
TOTAL LIABILITIES AND EQUITY (DEFICIT) |
|
$ |
|
|
$ |
|
||
The accompanying notes are an integral part of these consolidated financial statements.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands)
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
REVENUES |
|
|
|
|
|
|
|
|
|
|||
Product sales |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|||
Purchased crude oil sales |
|
|
|
|
|
|
|
|
|
|||
Water services |
|
|
|
|
|
|
|
|
|
|||
Other revenue |
|
|
|
|
|
|
|
|
|
|||
Total revenues |
|
|
|
|
|
|
|
|
|
|||
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|||
Cost of sales |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|||
Purchased crude oil expenses |
|
|
|
|
|
|
|
|
|
|||
Selling, general, and administrative |
|
|
|
|
|
|
|
|
|
|||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|||
Advertising and marketing |
|
|
|
|
|
|
|
|
|
|||
Loss on sale of assets |
|
|
|
|
|
|
|
|
|
|||
Impairment expense |
|
|
|
|
|
|
|
|
|
|||
Total operating expenses |
|
|
|
|
|
|
|
|
|
|||
INCOME FROM OPERATIONS |
|
|
|
|
|
|
|
|
|
|||
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|||
Interest income |
|
|
|
|
|
|
|
|
|
|||
Interest expense, net |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Gain (loss) on derivatives |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Loss on debt extinguishments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total other expenses |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
NET INCOME (LOSS) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
The accompanying notes are an integral part of these consolidated financial statements.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Changes in Equity (Deficit)
(in thousands, except share amounts)
|
|
Series A Preferred Shares |
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
Shares |
|
|
Amount |
|
|
Common Equity |
|
|
Retained Earnings (Accumulated Deficit) |
|
|
Total Equity (Deficit) |
|
|||||
Balance, December 31, 2022 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Contributions |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Distributions |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Balance, December 31, 2023 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Contributions |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Distributions |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Balance, December 31, 2024 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Issuances of Series A Preferred Shares |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Discount on Series A Preferred Shares |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
Amortization of Series A Preferred Shares discount |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Distributions on Series A Preferred Shares |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Balance, December 31, 2025 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
The accompanying notes are an integral part of these consolidated financial statements.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in thousands)
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|||
Net income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|||
Equity-based compensation expense |
|
|
|
|
|
|
|
|
|
|||
Amortization of right-of-use assets |
|
|
|
|
|
|
|
|
|
|||
Amortization of debt discount and debt issuance costs |
|
|
|
|
|
|
|
|
|
|||
Impairment expense |
|
|
|
|
|
|
|
|
|
|||
Write-offs of earnest payments |
|
|
|
|
|
|
|
|
|
|||
Unrealized (gain) loss on derivatives |
|
|
( |
) |
|
|
|
|
|
|
||
Loss on debt extinguishments |
|
|
|
|
|
|
|
|
|
|||
Loss on sale of assets |
|
|
|
|
|
|
|
|
|
|||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|||
Accounts receivable |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Earnest payments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Accounts payable |
|
|
|
|
|
( |
) |
|
|
|
||
Accrued expenses |
|
|
|
|
|
|
|
|
|
|||
Other current liabilities |
|
|
|
|
|
|
|
|
|
|||
Escrow account |
|
|
( |
) |
|
|
|
|
|
|
||
Accrued interest |
|
|
|
|
|
|
|
|
|
|||
Other operating activities |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Net cash provided by (used in) operating activities |
|
|
|
|
|
|
|
|
( |
) |
||
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|||
Additions to oil and gas properties and leases |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Proceeds from sale of assets |
|
|
|
|
|
|
|
|
|
|||
Additions to other property and equipment |
|
|
( |
) |
|
|
|
|
|
|
||
Other investing activities |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net cash used in investing activities |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|||
Proceeds from issuances of debt, net of discount |
|
|
|
|
|
|
|
|
|
|||
Payments of debt issuance costs |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Repayments of debt |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Proceeds from preferred equity offering, net of issuance costs |
|
|
|
|
|
|
|
|
|
|||
Distributions on Series A Preferred Shares dividends |
|
|
( |
) |
|
|
|
|
|
|
||
Member's contributions |
|
|
|
|
|
|
|
|
|
|||
Member's distributions |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Payments of deferred closings |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net cash provided by financing activities |
|
|
|
|
|
|
|
|
|
|||
Net change in cash and cash equivalents |
|
|
( |
) |
|
|
|
|
|
|
||
Cash and cash equivalents at beginning of year |
|
|
|
|
|
|
|
|
|
|||
Cash and cash equivalents at end of year |
|
$ |
|
|
$ |
|
|
$ |
|
|||
The accompanying notes are an integral part of these consolidated financial statements.
117
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1. Description of Business and Summary of Significant Accounting Policies
Business
Phoenix Energy One, LLC (“Phoenix Energy”), formerly known as Phoenix Capital Group Holdings, LLC (“Phoenix Capital”), is a Delaware limited liability company focused on oil and gas acquisitions and operations primarily in the Williston Basin, North Dakota/Montana, the Uinta Basin, Utah, the Permian Basin, Texas, the Denver-Julesburg Basin, Colorado/Wyoming and the Powder River Basin, Wyoming. The Company was formed in April 2019 and changed its name from Phoenix Capital Group Holdings, LLC to Phoenix Energy One, LLC in January 2025. As used in these consolidated financial statements, unless the context otherwise requires, references to the “Company,” “we,” “us,” and “our” refer to Phoenix Energy and its consolidated subsidiaries.
The Company’s strategy involves the acquisition of royalty assets, non-operated working interests, and operated leaseholds for the purpose of exploration, development, production, and sale of crude oil, natural gas, natural gas liquids, and other byproducts conducted through its wholly-owned subsidiaries, Phoenix Operating LLC (“PhoenixOp”), Firebird Services, LLC (“Firebird Services”), and Firebird Marketing, LLC (“Firebird Marketing”). PhoenixOp is a Delaware limited liability company formed in January 2022 to drill, complete and operate wells in the United States. Firebird Services is a Delaware limited liability company formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp. Firebird Marketing is a Delaware limited liability company formed in March 2025 to take title to oil at or near the wellhead and market production to third-party purchasers. It manages commercial and logistical activities related to the sale of hydrocarbons, including transportation coordination, blending and quality optimization, scheduling, and counterparty negotiations, and it assumes market, operational and credit risks related thereto. In return, Firebird Marketing may earn marketing margins based on market conditions and its ability to optimize sales execution.
Basis of preparation and principles of consolidation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of Phoenix Energy and its wholly-owned subsidiaries. All intercompany accounts and transactions with and between Phoenix Energy and its wholly-owned subsidiaries have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations or accumulated deficit.
Liquidity risk and management’s plans
Liquidity risk is the risk that the Company’s cash flows from operations will not be sufficient for the Company to continue operating and discharge its liabilities in the normal course of operations. The Company is exposed to liquidity risk as its continued operation is dependent upon its ability to continue to obtain financing, either in the form of debt or equity, or by continuing to achieve profitable operations in order to satisfy its liabilities as they come due.
As of December 31, 2025, the Company had negative working capital of approximately $
The Company may need to conduct asset sales, which is not a planned course of action, and/or issuances of debt and/or equity if liquidity risk increases in any given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, cost reductions and coordinating payment and revenue cycles.
The Company is required to evaluate whether or not its current financial condition, including its sources of liquidity at the date that the consolidated financial statements are issued, will enable the Company to meet its obligations as they come due within one year of the date of the issuance of these consolidated financial statements and to make a determination as to whether or not it is probable, under the application of this accounting guidance, that the Company will be able to continue as a going concern. In applying applicable accounting guidance, we considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows, the Company’s obligations due over the next twelve months as well as the Company’s recurring business
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
operating expenses, and believe to have sufficient financial resources to operate beyond the next twelve months following the date these consolidated financial statements are issued.
Use of estimates
The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the applicable reporting period of such statements. Accordingly, actual results could differ materially from these estimates.
The accompanying consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and natural gas liquids (“NGL”) reserves that are the basis for the calculations of depreciation, depletion, amortization, and determinations of impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered.
Segment information
As of December 31, 2025, the Company operates in three operating segments: Operating, Mineral and Non-operating, and Securities. The Company drills, extracts and operates wells under the Operating segment; acquires mineral interests and non-operated working interests in oil and gas properties under the Mineral and Non-operating segment; and conducts activities associated with its debt securities offerings under the Securities segment. All of the Company's operations are conducted in the United States. The Company's Chief Executive Officer, who is the Chief Operating Decision Maker (the “CODM”), reviews financial information on a disaggregated basis for purposes of determining how to allocate resources and assess performance (see Note 18 – Segments).
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents at financial institutions. The balances may exceed the Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there may be a concentration of credit risk related to amounts on deposit in excess of the FDIC insurance coverage.
Asset retirement obligations
The fair value of a liability for an asset’s retirement obligations is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. Over time, the liability is accreted for the change in its present value and the capitalized cost is depreciated over the useful life of the related asset. Accretion expense is recorded as a component of depreciation, depletion, and amortization expense on the Company's consolidated statements of operations. Asset retirement obligations (“ARO”) are periodically adjusted to reflect changes in the estimated present value of the obligation resulting from revisions to the estimated timing or amount of the expected future cash flows. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
Escrow account
Proceeds from investors who intend to purchase the Company’s bonds but have not yet closed the transaction are classified as escrow account on the consolidated balance sheets. Amounts are reclassified to debt upon the execution of the subscription agreement and, where applicable, the satisfactory verification of investor accreditation.
Accounts receivable
Accounts receivable consists of receivables from sales of oil, natural gas and NGL production delivered to purchasers and from joint interest owners on properties the Company operates. It also consists of uncollateralized mineral and royalty income due from third-party operators for oil and gas sales to purchasers and receipts from the Company’s mineral and non-operated working interest ownership.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
For receivables from joint interest owners on properties operated by PhoenixOp, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, receivables due to PhoenixOp are collected within two months.
In circumstances where the receivables relate to the Company’s mineral and non-operated working interests, purchasers remit payment for production to the operator and the operator, in turn, remits payment to the Company for the agreed-to royalties. Receivables are estimated in circumstances where the Company has not received actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized. Volume estimates for wells are based on (i) the historical actual data for months where the data is available, or (ii) engineering estimates for months where the historical actual data is not available. Pricing estimates are based on the average U.S. New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) spot oil prices for the month in which revenue is accrued.
The Company routinely reviews outstanding balances, assesses the financial strength of its counterparties, and if applicable, would record a reserve for credit losses for amounts not expected to be fully recovered. There was
Credit risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, accounts receivable, and derivative instruments. Accounts receivables are concentrated among operators and purchasers engaged in the energy industry within the United States, and this concentration has the potential to impact the Company's overall exposure to credit risk in that customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. By using derivative instruments to economically limit exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties have been determined to have an acceptable credit risk for the size of derivative position placed; therefore, the Company does not require collateral from its counterparties. Management periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.
Earnest payments
Earnest payments are deposits paid to oil and gas property owners upon the execution of a purchase and sale agreement or a lease agreement for the acquisition of their interests. These deposits are generally refundable and reclassified to oil and gas properties on the consolidated balance sheets upon successful completion of title review and closing of the transaction, or expensed in the event the transaction is not consummated or the deposit is not refunded. Earnest payments expensed for the years ended December 31, 2025 and 2024 were $
Oil and gas properties
The Company accounts for crude oil, natural gas and NGL exploration and development activities using the successful efforts method of accounting. Under this method, costs to acquire, drill, and complete development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Exploration costs, including geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but expensed if the well is determined to be unsuccessful. All capitalized well costs and leasehold costs of proved properties are depleted on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to a geologic basin.
Capitalized interest
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not yet subject to depletion. The amount capitalized is determined by multiplying the weighted-average cost of borrowings by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. Interest is capitalized only for the period that activities are in process to bring the projects to their intended use. The Company capitalized interest costs of $
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Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Impairment of long-lived assets
The Company follows the provisions of Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment, which requires that long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. The valuation of unproved oil and gas properties is subjective and requires management to make estimates and assumptions that, with the passage of time, may prove to be materially different from actual results. The unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. Management considers (i) estimated potential reserves and future net revenues from an independent reservoir engineer, (ii) its history in exploring the area, (iii) its future drilling plans per its capital drilling program prepared by its reservoir engineers and operations management, and (iv) other factors associated with the area. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made.
Other property and equipment
Other property and equipment consist primarily of furniture and fixtures and leasehold improvements, and are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives, which range from to
Revenue from contracts with customers
The Company recognizes its revenues following ASC 606, Revenue from Contracts with Customers (“ASC 606”). The Company’s revenues are predominantly derived from contracts for the sale of crude oil, natural gas and NGL. For crude oil, natural gas and NGL produced by PhoenixOp, each unit of production delivered is treated as a separate performance obligation that is satisfied at the point in time control of the product transfers to the customer. Revenue is measured as the amount the Company expects to receive in exchange for transferring commodities to the customer. The Company’s commodity sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as the Company controls the operated production prior to its transfer to customers.
In circumstances where the Company is the non-operator or mineral rights owner, the Company derives revenue from its interests in the sale of oil and natural gas production and does not consider itself to have control of the product, resulting in the recognition of revenues net of post-production expenses. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. Because of the timing lag between production, sales and receipt of statements from purchasers or operators, the Company records accrued revenue based on estimated production volumes and estimated commodity prices.
Effective April 2025, the Company began conducting marketing activities through its newly established subsidiary, Firebird Marketing. These activities include the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp, and the subsequent sale of the crude oil to customers. The Company concluded it acts as a principal in these transactions because it obtains control of the crude oil prior to transferring it to customers. Accordingly, revenues and associated purchase costs are recognized on a gross basis.
The Company, through Firebird Services, provides water disposal services to PhoenixOp and third parties with respect to oil and gas production from wells in which it is the operator. Pricing for such services represents a fixed
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
rate fee based on the quantity of water volume processed. Intercompany charges associated with PhoenixOp’s net interests are eliminated in consolidation. Revenue related to third-party working interest owners is recognized over time as the services are performed.
Allocation of transaction price to remaining performance obligations
Each unit of production delivered under the Company’s commodity sales contracts is treated as a separate performance obligation. Because the consideration associated with these contracts is variable and relates specifically to each unit of production delivered, the Company applies the practical expedient in ASC 606 that permits variable consideration to be allocated entirely to a wholly unsatisfied performance obligation. Accordingly, the Company is not required to disclose the transaction price allocated to remaining performance obligations.
Equity-based compensation
The Company accounts for equity-based compensation using the fair value method. The grant-date fair value attributable to the equity awards is calculated based on a combination of an income approach based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses. Equity awards are granted by Phoenix Equity Holdings, LLC (“Phoenix Equity”), the Company’s parent, and are measured at fair value on the date of grant. The Company records equity-based compensation expense and a capital contribution from Phoenix Equity for Class A and Class B Unit awards if the requisite service period is deemed to have been rendered and the performance condition, if applicable, is probable to be satisfied. Phantom Unit awards are accounted for as liability-classified awards and remeasured at fair value each reporting period until settlement. Forfeitures are recognized as they occur. For further discussion, see Note 12 – Equity-Based Compensation.
Fair value measurements
The Company follows ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards. ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable.
The three levels of the fair value measurement hierarchy are as follows:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3: Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).
The carrying values of the Company’s current financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable and other current liabilities, approximated their fair values at December 31, 2025 and 2024 because of the short-term nature of these instruments. The estimated fair values of the Company’s debt and operating lease liabilities approximated their carrying values using Level 2 fair value inputs as of December 31, 2025 and 2024. For a discussion of fair value measurements on the Company’s derivatives and asset retirement obligations, refer to Note 6 – Derivatives and Note 7 – Asset Retirement Obligations.
Deferred debt issuance costs
Deferred debt issuance costs represent fees and other direct incremental costs incurred in connection with the Company’s borrowings and offerings of the Company’s debt securities. Upon issuance of the debt, the associated debt issuance costs are reclassified as a discount on the outstanding debt and amortized into interest expense, net of capitalized interest, over the term of the debt using the effective interest method. The Company had
Income taxes
The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes. The pro rata share of taxable income or loss is ultimately included in the individual income tax returns of
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Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
the members of Phoenix Equity. Consequently, no provision for income taxes is made in the accompanying consolidated financial statements.
The Company remains subject to examination of its U.S. federal partnership tax returns for the tax years ended 2022 through 2025 and its state partnership tax returns for the tax years ended 2021 through 2025. Penalties and interest are classified as selling, general and administrative expense on the consolidated statements of operations.
Preferred equity
The Company evaluated the Series A Preferred Shares under ASC 480, Distinguishing Liabilities from Equity, to determine the appropriate classification. The Series A Preferred Shares (as defined in Note 10 – Preferred Equity) are not subject to any unconditional obligation to redeem for cash or other assets and do not contain redemption features that would require liability or temporary equity classification. Accordingly, they have been classified as permanent equity on the consolidated balance sheets. Distributions are accrued as contractually obligated and are paid quarterly in arrears, when, as and if declared by the Company's Board of Directors. The discount associated with the increasing-rate distributions is amortized using the effective interest method over the period preceding the commencement of the perpetual distribution rate. The accretion is recorded as an imputed distribution, recognized through retained earnings, with a corresponding increase to the carrying amount of the preferred equity.
Note 2. Recent Accounting Guidance
Recently adopted accounting standards
In October 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative (“ASU 2023-06”). ASU 2023-06 is intended to clarify or improve disclosure and presentation requirements of a variety of topics, which would allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the requirements, and align the requirements in the FASB accounting standard codification with the SEC’s regulations. The amendments in this ASU will be effective for public business entities on the effective date of the SEC’s removal of the related disclosures from Regulation S-X or Regulation S-K and should be applied prospectively. If the SEC has not removed the applicable requirements from Regulation S-X or Regulation S-K by June 30, 2027, the amendments will not become effective for any entity. The Company adopted the provisions of ASU 2023-06 on July 1, 2025, and the adoption of this standard did not have a material impact on the Company’s consolidated financial statements and related disclosures.
Recent accounting standards not yet adopted
In November 2024, the FASB issued ASU 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires disclosure in the Company's annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation, and amortization recognized as part of crude oil and natural gas producing activities, cost of sales, selling, general, and administrative expenses, and employee compensation. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03 can be applied prospectively or retrospectively at the Company’s election. The Company is currently evaluating the impact of the standard on its financial statements and disclosures and its plans for adoption, including the transition method and adoption date.
In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements (“ASU 2025-11”). ASU 2025-11 clarifies interim disclosure requirements and provides a comprehensive list of required interim disclosures. The update also incorporates a disclosure principle that requires entities to disclose events that occur after the end of the last annual reporting period. This update is effective for interim periods within annual periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the standard on its financial statements and disclosures.
Accounting pronouncements not listed above were assessed and determined to not have a material impact on the Company’s consolidated financial statements.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 3. Property, Plant, and Equipment
Property, plant, and equipment, net consist of the following:
|
|
December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Proved oil and natural gas properties(a) |
|
$ |
|
|
$ |
|
||
Unproved oil and natural gas properties |
|
|
|
|
|
|
||
Total oil and gas properties |
|
|
|
|
|
|
||
Other property and equipment |
|
|
|
|
|
|
||
Less: accumulated depreciation, depletion, and amortization |
|
|
( |
) |
|
|
( |
) |
Total property, plant, and equipment, net |
|
$ |
|
|
$ |
|
||
The Company considers a property proved when geological and engineering data can demonstrate with reasonable certainty that estimated quantities of oil, natural gas, and NGL can be recoverable from known reservoirs in future periods under the economic and operating conditions (i.e., prices and costs) that exist at the time the estimates are made.
A property is unproved when there are currently no producing wells pooling the property. For the majority of the value of the unproven properties in 2025, the Company has analyzed the wells within a 10-mile radius of the property to conclude the property is economically viable for oil extraction and has the potential to be drilled and become proved reserves.
The Company uses the successful efforts method of accounting for its oil and gas properties. Property acquisition costs are depleted on a units-of-production basis over total proved reserves, while costs of wells and related equipment and facilities are depleted on a units-of-production basis over proved developed reserves. Depletion on oil and gas properties was $
Depreciation expense on the Company’s equipment and other property was less than $
Impairment
When the Company performs its annual impairment test or circumstances indicate that the proved oil and gas properties may be impaired, the Company compares expected undiscounted future cash flows to the assets’ carrying value grouped by geologic basin. If the undiscounted future cash flows, based on the Company’s estimate of significant Level 3 inputs, including futures prices, anticipated production from proved reserves and other relevant data, are lower than the assets’ carrying value, the carrying value is reduced to fair value. Impairment expense also includes write-offs associated with title defects and lease expirations of the Company’s oil and gas properties, which totaled $
Note 4. Revenue
Revenue from contracts with customers is presented as product sales and mineral and royalty revenues on the consolidated statements of operations. PhoenixOp typically receives payment monthly for the commodities it extracts and delivers to purchasers, and the Company is paid mineral and royalty revenue monthly by the various operators and working interest owners within the pooled units that the Company owns. Product sales revenues within the operating segment are presented separately from post-production costs, including transportation costs, whereas mineral and royalty revenues within the mineral and non-operating segment are presented net of post-production costs charged by the operator, on the consolidated statements of operations. Other costs, including severance taxes and lease operating expenses are presented as cost of sales on the consolidated statements of operations for both the operating and mineral and non-operating segments.
The Company generates revenues from the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp, and the subsequent sale of the crude oil to customers. The
124
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Company acts as the principal in these transactions and therefore recognizes the associated revenues and purchase costs on a gross basis in accordance with ASC 606.
The Company also generates revenues from performing saltwater disposal services on wells in which it is the operator. Revenues are driven primarily by the volumes of produced water and flowback water the Company injects into its saltwater disposal facilities and the fees the Company charges for these services. Fees are charged on a per-barrel basis and are recognized as revenues in accordance with ASC 606.
Other revenue is comprised of redemption fees that are charged to investors, generally upon the early redemption of their investments. For the securities segment, other revenue also includes intersegment interest revenue earned from the operating and mineral and non-operating segments that is eliminated on the consolidated statements of operations.
The following tables present the Company’s revenue from contracts with customers and other revenue for the years ended December 31, 2025, 2024, and 2023, by segment:
|
|
Year Ended December 31, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Purchased crude oil sales |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
||||
Water services |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Intersegment revenue |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
||||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
125
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
|
|
Year Ended December 31, 2024 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Water services |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Intersegment revenue |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
||||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
|
|
Year Ended December 31, 2023 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Intersegment revenue |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
||||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
Customer Concentration
The following table summarizes major customers that make up
|
|
December 31, |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
Customer A |
|
|
% |
|
|
% |
||
Customer B |
|
|
% |
|
|
% |
||
Customer C |
|
|
% |
|
|
% |
||
Customer D |
|
|
% |
|
|
% |
||
The following table summarizes major customers that make up
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Customer A |
|
|
% |
|
|
% |
|
|
% |
|||
Customer E |
|
|
% |
|
|
% |
|
|
% |
|||
Customer F |
|
|
% |
|
|
% |
|
|
% |
|||
126
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 5. Other Current Assets
The following table summarizes the Company’s other current assets for the periods presented:
|
|
December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Derivative assets |
|
$ |
|
|
$ |
|
||
Prepaid expenses |
|
|
|
|
|
|
||
Insurance recovery receivable |
|
|
|
|
|
|
||
Deferred financing costs |
|
|
|
|
|
|
||
Deposits |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
||
Note 6. Derivatives
The Company periodically enters into commodity derivative contracts to manage its exposure to crude oil price risk. Additionally, the Company is required to hedge a portion of anticipated crude oil production for future periods pursuant to its debt covenants under the Fortress Credit Agreement, as further described in Note 8 – Debt. The Company does not enter into derivative contracts for speculative trading purposes.
When the Company utilizes crude oil commodity derivative contracts, it expects to enter into put/call collars, fixed swaps or put options to hedge a portion of its anticipated future production. A collar contract establishes a floor and ceiling price on contracted volumes and provides payment to the Company if the index price falls below the floor or requires payment by the Company if the index price rises above the ceiling. A fixed swap contract sets a fixed price and provides payment to the Company if the index price is below the fixed price or requires payment by the Company if the index price is above the fixed price. A put arrangement gives the Company the right to sell the underlying crude oil commodity at a strike price and provides payment to the Company if the index price falls below the strike price. For put arrangements, no payment or receipt occurs if the index price is higher than the strike price. As of December 31, 2025, the Company’s derivatives were comprised of crude oil commodity derivative contracts indexed to the NYMEX WTI. The Company has not designated its derivative contracts for hedge accounting and, as a result, records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in its consolidated statements of operations. All derivative contracts are recorded at fair market value and included on the consolidated balance sheets as assets or liabilities. Derivative assets and liabilities are presented net on the consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.
As of December 31, 2025, the Company’s open crude oil derivative contracts consisted of the following:
|
|
Settlement Period |
|
|||||||||
(volumes in Bbl and prices in $/Bbl) |
|
2026 |
|
|
2027 |
|
|
2028 |
|
|||
Two-Way Collars |
|
|
|
|
|
|
|
|
|
|||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|||
Weighted Average Ceiling Price |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Weighted Average Floor Price |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Swaps |
|
|
|
|
|
|
|
|
|
|||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|||
Weighted Average Contract Price |
|
$ |
|
|
$ |
|
|
$ |
|
|||
The following table summarizes the gains and losses on derivative instruments included on the consolidated statements of operations and the net cash payments related thereto for the periods presented. Cash flows associated with these non-hedge designated derivatives are reported within operating activities on the consolidated statements of cash flows.
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Gain (loss) on derivative instruments |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Net cash receipts on derivatives |
|
|
|
|
|
|
|
|
|
|||
127
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.
The following tables provide (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2025 and 2024. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.
|
|
December 31, 2025 |
|
|||||||||||||||||||||||
(in thousands) |
|
Balance Sheet Location |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total Gross |
|
|
Gross |
|
|
Net Fair |
|
||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Other current assets |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Commodity derivatives |
|
Other noncurrent assets |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Other current liabilities |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Commodity derivatives |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
|
|
|
|
|||
Total liabilities |
|
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
|
|
December 31, 2024 |
|
|||||||||||||||||||||||
(in thousands) |
|
Balance Sheet Location |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total Gross |
|
|
Gross |
|
|
Net Fair |
|
||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Other current assets |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Commodity derivatives |
|
Other noncurrent assets |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Other current liabilities |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
Commodity derivatives |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
|
|
|
( |
) |
||
Total liabilities |
|
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
128
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 7. Asset Retirement Obligations
The Company’s asset retirement obligations relate to the future plugging and abandonment of wells and related facilities. As of December 31, 2025 and 2024, the net present value of the total ARO was estimated to be $
The following table summarizes the changes in the ARO for the periods presented:
|
|
Year Ended December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Asset retirement obligations at beginning of period |
|
$ |
|
|
$ |
|
||
Additions |
|
|
|
|
|
|
||
Derecognition |
|
|
( |
) |
|
|
( |
) |
Accretion |
|
|
|
|
|
|
||
Revisions in estimated cash flows |
|
|
|
|
|
|
||
Asset retirement obligations at end of period(a) |
|
$ |
|
|
$ |
|
||
ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate, and well life. The inputs are calculated based on historical data as well as current estimated costs.
Note 8. Debt
The following table summarizes the Company’s long-term debt for the periods presented:
|
|
Maturity Date |
|
|
|
December 31, |
|
|||||||||
(in thousands) |
|
Earliest Date |
|
|
Latest Date |
|
Interest Rate(a) |
|
2025 |
|
|
2024 |
|
|||
Fortress Term Loans |
|
|
— |
|
|
|
Term SOFR + |
|
$ |
|
|
$ |
|
|||
Unregistered Debt Offerings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Regulation D Bonds |
|
|
|
|
|
|
|
|
|
|
||||||
Adamantium Securities |
|
|
|
|
|
|
|
|
|
|
||||||
Regulation A Bonds |
|
|
|
|
|
|
|
|
|
|
||||||
Exchange Notes |
|
|
|
|
|
|
|
|
|
|
||||||
Total unregistered debt offerings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Registered Notes |
|
|
|
|
|
|
|
|
|
|
||||||
Total outstanding debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Less: Unamortized debt discount and issuance costs(b) |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Less: Current portion of long-term debt |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Total long-term debt, net of current portion |
|
|
|
|
|
|
|
|
$ |
|
|
$ |
|
|||
129
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following table summarizes the aggregate contractual annual maturities for the Company’s long-term debt outstanding as of December 31, 2025, excluding unamortized debt discount and issuance costs:
(in thousands) |
|
|
|
|
Year Ending December 31, |
|
Amount |
|
|
2026 |
|
$ |
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
2029 |
|
|
|
|
2030 |
|
|
|
|
Thereafter |
|
|
|
|
Total |
|
$ |
|
|
Fortress Credit Agreement
In April 2025, the Company amended the secured credit agreement with Fortress Credit Corp. (the “Fortress Credit Agreement”) to establish a new tranche of term loans in an aggregate principal amount of $
In August 2025, the Fortress Credit Agreement was syndicated to include an additional institutional lender and further amended to establish an additional tranche of term loans in an aggregate principal amount of $
In October 2025, the Fortress Credit Agreement was further amended to establish a tranche of commitments to make term loans available in an aggregate principal amount of $
The Company evaluated the April, August and October 2025 Fortress Amendments and determined the August Fortress Amendment was accounted for as a new debt issuance, while the April and October Fortress Amendments were accounted for as debt modifications. Accordingly, fees and expenses associated with the August Fortress Amendment were capitalized and amortized over the term of the related debt, and existing unamortized debt issuance costs related to the April and October Fortress Amendments continue to be amortized over the remaining term of the modified debt.
The term loans under the Fortress Credit Agreement (the “Fortress Term Loans”) bear interest at a rate per annum equal to Term Secured Overnight Financing Rate (“SOFR”) plus a margin of
Obligations under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Equity and its subsidiaries that have guaranteed the obligations of the Company under the Fortress Credit Agreement, subject to certain exceptions.
The Company had an aggregate principal amount outstanding of $
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
the Company’s proved developed reserves for a 36-month period, pursuant to the terms of the Fortress Credit Agreement. See Note 6 – Derivatives.
Registered Notes
In October 2024, the Company filed a registration statement on Form S-1 with the SEC, which was declared effective in May 2025, with respect to the continuous offering of up to $
The Registered Notes are contractually senior to bonds sold pursuant to offerings under Rule 506(c) of Regulation D under the Securities Act (the “Regulation D Bonds”) that commenced in December 2022 (the “December 2022 506(c) Bonds”) and August 2023 (the “August 2023 506(c) Bonds”), and subordinated to the term loans under the Fortress Credit Agreement, the Adamantium Securities, and the Senior Reg D Bonds. The Registered Notes contain customary events of default and may be redeemed at the option of the Company at any time without premium or penalty. The holders of Registered Notes also have a right to request redemption of their notes in certain circumstances at a discount to par, subject to a limit of
Unregistered Debt Offerings
Regulation D Bonds
In May 2025, the Company approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $
Regulation A Bonds and Exchange Notes
In May 2025, the Company entered into an indenture to issue to holders of its unsecured three-year
Adamantium Securities
In September 2023, the Company, through its wholly-owned subsidiary, Adamantium, commenced an offering of bonds exempt from registration pursuant to Rule 506(c) of Regulation D (the “Adamantium Bonds”). The Adamantium Bonds offer high net worth individuals a debt instrument that is unsecured but structurally senior to other bonds sold by the Company under Regulation A and Regulation D. The Adamantium Bonds have maturity terms that range from five to eleven years and bear interest ranging from
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Interest Expense on Debt
The following table summarizes the total interest costs incurred on the Company’s debt:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Stated interest |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Amortization of debt discount and debt issuance costs |
|
|
|
|
|
|
|
|
|
|||
Total interest cost |
|
|
|
|
|
|
|
|
|
|||
Capitalized interest |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total interest expense, net |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Note 9. Other Current Liabilities
The following table summarizes the Company’s other current liabilities for the periods presented:
|
|
December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Revenue payables |
|
$ |
|
|
$ |
|
||
Advances from joint interest partners |
|
|
|
|
|
|
||
Production taxes payable |
|
|
|
|
|
|
||
Accrued interest |
|
|
|
|
|
|
||
Unredeemed matured bonds |
|
|
|
|
|
|
||
Dividends payable |
|
|
|
|
|
|
||
Asset retirement obligations |
|
|
|
|
|
|
||
|
|
|
|
|
|
|||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
||
In circumstances where the Company serves as the operator, the Company receives production proceeds from purchasers and distributes revenue to royalty owners and working interest owners based on their ownership interests. Production proceeds that the Company has not yet distributed are reflected as revenue payables and classified as a component of other current liabilities on the consolidated balance sheets. Production taxes payable represents production taxes assessed on the Company’s operated volumes that have been incurred but not yet remitted as of the balance sheet date. Additionally, working interest owners who participate in our wells may elect to prepay a portion of the estimated drilling and completion costs. For such advances, a liability is recorded and subsequently reduced as the associated work is performed and billed to the working interest owners.
Note 10. Preferred Equity
In September 2025, the Company completed its offering of the Series A Cumulative Redeemable Preferred Shares (the “Series A Preferred Shares”) pursuant to Regulation A promulgated under the Securities Act of 1933, as amended, which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025. The Company sold an aggregate of
Voting Rights
Holders of the Series A Preferred Shares generally have no voting rights. However, if the Company does not pay distributions on the Series A Preferred Shares for six or more quarterly distribution periods (whether or not consecutive), the holders of the Series A Preferred Shares will be entitled to vote for the election of two additional
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
directors to serve on the Board of Directors until the Company pays, or declares and sets aside funds for the payment of, all distributions that the Company owes on the Series A Preferred Shares.
Dividend Rights
The Series A Preferred Shares rank senior to all classes of equity securities issued by the Company (including common equity) and are junior to all existing and future indebtedness of the Company. Holders of the Series A Preferred Shares are entitled to receive cumulative cash distributions based on the initial liquidation preference of $
Liquidation Rights
In the event of the Company’s voluntary or involuntary liquidation, dissolution, or winding up, the holders of the Series A Preferred Shares will generally have the right to receive the initial liquidation preference of $
Redemption Rights
The Series A Preferred Shares are not redeemable at the option of the holders. The Series A Preferred Shares, are, however, redeemable at the Company’s option, in whole or in part, at a cash redemption price of $
Conversion
The Series A Preferred Shares are not convertible or exchangeable for any securities or property of the Company.
Note 11. Deferred Closings
Deferred closings represent agreements entered into by the Company with mineral interest owners that provide for the acquisition price to be paid in installments. Deferred closing arrangements typically have terms ranging from
The following table summarizes the aggregate annual contractual settlements for the Company’s deferred closing arrangements as of December 31, 2025:
(in thousands) |
|
|
|
|
Year Ending December 31, |
|
Amount |
|
|
2026 |
|
$ |
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
2029 |
|
|
|
|
2030 |
|
|
|
|
Thereafter |
|
|
|
|
Total |
|
$ |
|
|
Note 12. Equity-Based Compensation
The Company’s parent, Phoenix Equity, has granted equity awards to employees and non-employee service providers of the Company under the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”). Phoenix Equity is authorized to issue up to
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
granted to certain executives of the Company in exchange for previously awarded equity awards and were deemed fully vested as of the modification date.
A summary of the activity under the 2024 Incentive Plan for the years ended December 31, 2025 and 2024 is presented below.
|
|
Number of Units |
|
|
Weighted |
|
||
Nonvested at December 31, 2023 |
|
|
|
|
|
|
||
Granted - Class A Units |
|
|
|
|
$ |
|
||
Granted - Class B Units |
|
|
|
|
|
|
||
Vested |
|
|
|
|
|
|
||
Forfeited |
|
|
|
|
|
|
||
Nonvested at December 31, 2024 |
|
|
|
|
|
|
||
Granted - Class A Units |
|
|
|
|
|
|
||
Granted - Class B Units |
|
|
|
|
|
|
||
Granted - Phantom Units |
|
|
|
|
|
|
||
Vested |
|
|
( |
) |
|
|
|
|
Forfeited |
|
|
( |
) |
|
|
|
|
Nonvested at December 31, 2025 |
|
|
|
|
|
|
||
Phoenix Equity granted
Phoenix Equity granted
As of December 31, 2025 and 2024, there was $
The fair value of each unit granted under the 2024 Incentive Plan was valued on the date of grant under an independent third-party valuation, which included a combination of an income approach, based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
average assumptions used in the valuation of performance unit awards granted for the years ended December 31, 2025 and 2024, are presented in the table below:
|
|
2025 |
|
|
2024 |
|
||
Dividend yield(a) |
|
|
% |
|
|
% |
||
Risk-free interest rate(b) |
|
|
% |
|
|
% |
||
Expected volatility(c) |
|
|
% |
|
|
% |
||
Expected term (in years)(d) |
|
|
|
|
|
|
||
Discount for lack of marketability(e) |
|
|
% |
|
|
% |
||
Note 13. Related Parties
Debt Offerings
Certain of the Company’s officers and their family members participate in the Company’s unregistered debt offerings. During the years ended December 31, 2025, 2024, and 2023, these officers and their family members purchased, in aggregate,
Lion of Judah
The Company paid interest expense to a financial institution on behalf of Lion of Judah related to a certain financing agreement between Lion of Judah and the financial institution of less than $
Note 14. Leases
The Company leases its office facilities primarily under noncancelable multi-year operating lease agreements. The Company determines whether a contract contains a lease at inception by determining if the contract conveys the right to control the use of identified office space for a period of time in exchange for consideration. The Company’s lease agreements contain lease and non-lease components, which are generally accounted for separately with amounts allocated to the lease and non-lease components based on relative stand-alone prices.
Right of use (“ROU”) assets and lease liabilities are recognized at the commencement date based on the present value of the future minimum lease payments over the lease term. Renewal and termination clauses that are factored into the determination of the lease term if it is reasonably certain that these options would be exercised by the Company. Lease assets are amortized over the lease term unless there is a transfer of title or purchase option reasonably certain of exercise, in which case the asset life is used. The Company’s lease agreements include variable payments. Variable lease payments not dependent on an index or rate primarily consist of common area maintenance charges and are not included in the calculation of the ROU asset and lease liability and are expensed as incurred. In order to determine the present value of lease payments, the Company uses the implicit rate when it is readily determinable or the Company’s incremental borrowing rate based on the Company’s existing line of credit facilities.
The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As of December 31, 2025, the Company does not have leases where it is involved with the construction or design of an underlying asset, has no material obligation for leases signed but not yet commenced and does not have any material sublease activities.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following table summarizes the Company’s future minimum lease payments as of December 31, 2025:
(in thousands) |
|
|
|
|
Year Ending December 31, |
|
Amount |
|
|
2026 |
|
$ |
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
2029 |
|
|
|
|
2030 |
|
|
|
|
Thereafter |
|
|
|
|
Total lease payments |
|
|
|
|
Less: interest |
|
|
( |
) |
Present value of lease liabilities |
|
$ |
|
|
The following table shows the line item classification of the Company’s right-of-use assets and lease liabilities on the Company’s consolidated balance sheets:
|
|
|
|
December 31, |
|
|||||
(in thousands) |
|
Line item |
|
2025 |
|
|
2024 |
|
||
Right-of-use assets – operating |
|
Right-of-use assets, net |
|
$ |
|
|
$ |
|
||
Total right-of-use assets |
|
|
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
|
|
||
Current operating lease liabilities |
|
Current operating lease liabilities |
|
$ |
|
|
$ |
|
||
Noncurrent operating lease liabilities |
|
Operating lease liabilities |
|
|
|
|
|
|
||
Total lease liabilities |
|
|
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
|
|
||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
|
|
||
Weighted average discount rate |
|
|
|
|
% |
|
|
% |
||
The following table shows the components of the Company’s lease expense for the years ended December 31, 2025, 2024, and 2023:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Operating leases(a) |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Short-term leases(a) |
|
|
|
|
|
|
|
|
|
|||
Variable lease payments(a) |
|
|
|
|
|
|
|
|
|
|||
Net operating lease cost |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Note 15. Defined Contribution Plan
The Company has a 401(k) defined contribution plan which permits participating employees to defer up to a maximum of
Note 16. Commitments and Contingencies
For a summary of the Company’s lease obligations, see Note 14 – Leases.
Litigation
From time to time, the Company may become involved in other legal proceedings or be subject to claims arising in the ordinary course of business. Although the results of ordinary course litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its business, financial condition, results of operations or cash flows. Regardless of the
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
outcome, litigation can have an adverse impact because of defense and settlement costs, diversion of management resources and other factors.
Drilling Rig Contracts
The Company has entered into drilling rig contracts to procure drilling services for wells operated by PhoenixOp. The contracts are short-term and provide a daily operating rate as consideration for services performed by the third-party provider. As of December 31, 2025, the Company was subject to $
Natural Gas Processing Contracts
The Company has entered into contracts for mobile cryogenic gas processing units to process raw gas, produce and store NGL, and compress residue natural gas at wells operated by PhoenixOp. The contracts range from 6 months to 36 months and provide monthly facility and service fees as consideration for services performed by the third-party provider. As of December 31, 2025, the Company was subject to $
Generator Contracts
The Company has entered into contracts with a third-party provider to supply generators used to provide power at wells operated by PhoenixOp. The contracts range from 12 months to 24 months and require monthly service payments for power generation and related equipment. As of December 31, 2025, the Company had approximately $
Saltwater Disposal Pump Contracts
The Company has entered into contracts for pumps which are used to inject produced water and flowback into its saltwater disposal facilities on wells for which PhoenixOp serves as the operator. The contracts provide for monthly payments and have terms of twelve months or less. As of December 31, 2025, the Company had approximately $
Delivery Commitments
PhoenixOp is subject to arrangements pursuant to which it has committed to deliver barrels of crude oil to a purchaser through 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 its 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. The Company delivered
Note 17. Supplemental Cash Flow Information
The following table summarizes supplemental information to the consolidated statements of cash flows for the periods presented:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
|
|||
Cash interest paid, net of capitalized interest |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Cash paid for operating leases |
|
|
|
|
|
|
|
|
|
|||
Supplemental disclosure of non-cash transactions: |
|
|
|
|
|
|
|
|
|
|||
Capital expenditures in accounts payable and accrued expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Unpaid property acquisition costs in deferred closings |
|
|
|
|
|
|
|
|
|
|||
Right-of-use asset obtained in exchange for lease liability |
|
|
|
|
|
|
|
|
|
|||
Modification of right-of-use asset and lease liability |
|
|
|
|
|
|
|
|
|
|||
Series A Preferred Shares distributions declared but unpaid |
|
|
|
|
|
|
|
|
|
|||
Series A Preferred Shares discount accretion |
|
|
|
|
|
|
|
|
|
|||
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 18. Segments
Segment operating profit is used as a performance metric by the CODM in determining how to allocate resources and assess performance as this measure provides insight into the segments’ operations and overall success of a segment for a given period. Segment operating profit is calculated as total segment revenue less operating costs attributable to the segment, which includes allocated corporate costs that are overhead in nature and not directly associated with the segments, such as certain general and administrative expenses, executive or shared-function payroll costs and certain limited marketing activities. Corporate costs are allocated to the segments based on usage and headcount, as appropriate. Segment operating profit excludes other income and expense, such as interest expense, interest income, gain (loss) on derivatives, loss on debt extinguishments, even though these amounts are allocated to the segments and provided to the CODM. Transactions between segments are accounted for on an accrual basis and are eliminated upon consolidation. Interest expense is allocated to the segments based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date, and interest income and gain (loss) on derivatives are allocated using the same basis as corporate costs.
The following table summarizes segment operating profit and reconciliation to net income (loss) for the periods presented:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Segment operating profit |
|
|
|
|
|
|
|
|
|
|||
Operating |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|||
Securities |
|
|
|
|
|
|
|
|
|
|||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total segment operating profit |
|
|
|
|
|
|
|
|
|
|||
Interest income |
|
|
|
|
|
|
|
|
|
|||
Interest expense |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Gain (loss) on derivatives |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Loss on debt extinguishments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net income (loss) |
|
$ |
|
|
|
( |
) |
|
|
( |
) |
|
138
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following tables present financial information by segment as of December 31, 2025 and 2024, and for the years ended December 31, 2025, 2024, and 2023.
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Significant expenses |
|
|
|
|
|
|
|
|
|
|||
Operating |
|
|
|
|
|
|
|
|
|
|||
Cost of sales |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|||
Purchased crude oil expenses |
|
|
|
|
|
|
|
|
|
|||
Selling, general, and administrative |
|
|
|
|
|
|
|
|
|
|||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|||
Other segment item(a) |
|
|
|
|
|
|
|
|
|
|||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|||
Cost of sales |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|||
Selling, general, and administrative |
|
|
|
|
|
|
|
|
|
|||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|||
Other segment items(b) |
|
|
|
|
|
|
|
|
|
|||
Securities |
|
|
|
|
|
|
|
|
|
|||
Advertising and marketing |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Selling, general, and administrative |
|
|
|
|
|
|
|
|
|
|||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|||
Interest expense |
|
|
|
|
|
|
|
|
|
|||
Operating |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|||
Securities |
|
|
|
|
|
|
|
|
|
|||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total interest expense, net |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|||
Operating |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
|
|
Total capital expenditures |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Assets |
|
|
|
|
|
|
||
Operating |
|
$ |
|
|
$ |
|
||
Mineral and Non-operating |
|
|
|
|
|
|
||
Securities |
|
|
|
|
|
|
||
Eliminations |
|
|
( |
) |
|
|
( |
) |
Total assets |
|
$ |
|
|
$ |
|
||
139
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following tables summarize the Company’s oil and natural properties by proved and unproved properties, location and by segment (before accumulated depletion):
|
|
December 31, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Consolidated |
|
|||||
Oil and natural gas properties, proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Oil and natural gas properties, unproved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total unproved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
|
|
December 31, 2024 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Consolidated |
|
|||||
Oil and natural gas properties, proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Oil and natural gas properties, unproved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total unproved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Note 19. Subsequent Events
Management has evaluated subsequent events through March 17, 2026, in connection with the preparation of these consolidated financial statements, which is the date the consolidated financial statements were available to be issued. The Company has determined that there were no material such events that warrant disclosure or recognition on the consolidated financial statements, except for the following:
In January 2026, the Company paid cash distributions totaling $
140
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
In February 2026, the Fortress Credit Agreement was further amended to provide for a new $
In February 2026, the Company entered into crude oil fixed-price swap agreements with a counterparty that incorporate long call options with a strike price of $
In March 2026, the Company also executed long call option contracts with a strike price of $
On March 16, 2026, the Company approved an increased to the maximum offering amount of the August 2023 506(c) Bonds from $
Furthermore, on March 16, 2026, the Company amended the Adamantium Loan Agreement to increase the amount available to borrow under agreement from $
The Company is continuing to raise debt capital under its exempt and registered debt offerings. Since the balance sheet date and through the date of filing of these consolidated financial statements, the Company issued approximately $
Note 20. Supplemental Information on Oil and Natural Gas Operations (unaudited)
Geographic Area of Operations
All of the Company’s proved reserves are located within the continental United States, with the majority concentrated in North Dakota, Montana, Utah, Texas, Colorado and Wyoming.
Costs Incurred in Oil and Natural Gas Property Acquisitions and Development Activities
Costs incurred in oil and natural gas property acquisition and development, whether capitalized or expensed, are presented below:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Acquisition Costs of Properties |
|
|
|
|
|
|
|
|
|
|||
Proved |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Unproved |
|
|
|
|
|
|
|
|
|
|||
Development Costs |
|
|
|
|
|
|
|
|
|
|||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
|||
141
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat and gather natural gas.
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization including impairments, are presented below:
|
|
December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Proved oil and natural gas properties |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Unproved oil and natural gas properties |
|
|
|
|
|
|
|
|
|
|||
Total oil and gas properties |
|
|
|
|
|
|
|
|
|
|||
Less: Accumulated depletion |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Oil and gas properties, net |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Oil and Natural Gas Reserve Information
The following table sets forth estimated net quantities of the Company’s proved developed oil and natural gas reserves. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. For estimates of oil reserves, the average NYMEX WTI spot oil prices used were $
142
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.
Proved Developed and Undeveloped Reserves: |
|
Oil |
|
|
Natural Gas |
|
|
Natural Gas |
|
|
Total |
|
||||
As of December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Production |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Purchases of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Extensions and discoveries |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revisions of previous estimates |
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||
As of December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Production |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Divestitures |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Purchases of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Extensions and discoveries |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revisions of previous estimates |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
As of December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Production |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Divestitures |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Purchases of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Extensions and discoveries |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revisions of previous estimates |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
As of December 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Proved Developed Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Proved Undeveloped Reserves(b) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
At December 31, 2025, total estimated proved reserves were approximately
143
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
At December 31, 2024, total estimated proved reserves were approximately
At December 31, 2023, total estimated proved reserves were approximately
144
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves.
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Future cash inflows |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Future development costs |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Future production costs |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Future net cash flows |
|
|
|
|
|
|
|
|
|
|||
Less |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Standard measure of discounted future net cash flows |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Changes in the Standardized Measure for Discounted Cash Flows
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Beginning of the year |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Net change in sales and transfer prices and in production (lifting) costs related to future production |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Changes in the estimated future development costs |
|
|
( |
) |
|
|
|
|
|
|
||
Sales and transfers of oil and gas produced during the period |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net change due to extensions, discoveries, and improved recovery |
|
|
|
|
|
|
|
|
|
|||
Net change due to purchases and sales of minerals in place |
|
|
|
|
|
|
|
|
|
|||
Net change due to revisions in quantity estimates |
|
|
( |
) |
|
|
|
|
|
|
||
Previously estimated development costs incurred during the period |
|
|
|
|
|
|
|
|
|
|||
Accretion of discount |
|
|
|
|
|
|
|
|
|
|||
End of the year |
|
$ |
|
|
$ |
|
|
$ |
|
|||
The data presented in this note should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimations and assumptions. The required projection of production and related expenditures overtime requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
145
Table of Contents
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Limitations on Effectiveness of Controls and Procedures
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated, as of the end of the period covered by this Annual Report, the effectiveness of our disclosure controls and procedures (as that term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2025, as a result of the material weaknesses described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. In connection with the audits of our consolidated financial statements as of and for the year ended December 31, 2025, our auditors identified several material weaknesses in our internal control over financial reporting. The material weaknesses identified were: (i) inadequate segregation of duties within key financial areas; (ii) entity-level controls that were not sufficiently designed, documented or consistently maintained across the Committee of Sponsoring Organizations of the Treadway Commission (COSO) components to provide reasonable assurance that material misstatements would be prevented or detected on a timely basis; (iii) ineffective processes for identifying and assessing risks impacting internal control over financial reporting; (iv) insufficient evaluation and determination as to whether components of internal controls were present and functioning; (v) ineffective information technology general controls supporting the financial reporting process; and (vi) ineffective controls over the completeness and accuracy of information used in the operation of control activities.
These material weaknesses did not result in any identified material misstatements in the Company’s consolidated financial statements included in this Annual Report. However, these material weaknesses could result in a misstatement of the Company’s financial statements that would not be prevented or detected on a timely basis.
Management’s Remediation Efforts
Management has begun implementing measures designed to remediate the material weaknesses described above. These remediation efforts include, but are not limited to: enhancing segregation of duties within financial reporting and related systems; enhancing the design and documentation of entity-level controls across the COSO components; strengthening the Company's formal risk assessment processes related to financial reporting; implementing additional procedures to evaluate whether internal control components are present and functioning; implementing improvements to information technology general controls, including user access management, system change management, and system monitoring controls; establishing additional controls over the completeness and accuracy of information used in financial reporting processes; and expanding internal control documentation, training and monitoring activities.
These measures include engaging with external consulting firms to assist with technical accounting matters and to improve the design and operating effectiveness of our internal control over financial reporting. In addition, the Company implemented a new accounting system effective January 1, 2026, which management believes will enhance financial reporting processes and support improvements to internal control over financial reporting. The Company will continue to evaluate the effectiveness of controls associated with this system as part of its remediation efforts.
146
Table of Contents
Management’s Annual Report on Internal Control over Financial Reporting
This Annual Report does not include a report of management’s assessment regarding our internal control over financial reporting or an attestation report of our independent registered accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Control over Financial Reporting
We are taking actions to remediate the material weaknesses relating to our internal control over financial reporting, as described above. Except as discussed above, there were no changes in our internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the year ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
147
Table of Contents
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth certain information about our executive officers, directors, and significant employees as of the date of this Annual Report:
Name |
|
Age |
|
Position |
|
Since |
Executive Officers |
|
|
|
|
|
|
Adam Ferrari |
|
43 |
|
Chief Executive Officer and Director |
|
November 2023 |
Curtis Allen |
|
40 |
|
Chief Financial Officer and Director |
|
February 2020 |
David Scadden |
|
36 |
|
Chief Operating Officer |
|
November 2025 |
Lindsey Wilson |
|
41 |
|
Chief Business Officer |
|
December 2024 |
Sean Goodnight |
|
51 |
|
Chief Acquisition Officer |
|
June 2020 |
Justin Arn |
|
45 |
|
Chief Land and Title Officer |
|
April 2020 |
David Wheeler |
|
51 |
|
Chief Legal Officer |
|
October 2024 |
Directors |
|
|
|
|
|
|
Daniel Ferrari |
|
76 |
|
Director |
|
September 2025 |
Jason Allan Pangracs |
|
52 |
|
Director |
|
September 2025 |
Jason Montgomery Wagner |
|
54 |
|
Director(1) |
|
September 2025 |
Significant Employees |
|
|
|
|
|
|
Matthew Willer |
|
49 |
|
Managing Director, Capital Markets |
|
March 2021 |
Set forth below is a brief description of the business experience of our directors and each of our executive officers and significant employees.
Adam Ferrari. Adam has been our Chief Executive Officer since November 2023, and a member of our board of directors since September 2025. Adam also served as our Manager from November 2023, until our reorganization to a manager-managed LLCA with a board of directors. Adam served as our Vice President of Engineering from April 2023 until November 2023, during which time he was responsible for conducting engineering evaluations across all areas of interest and making purchase recommendations to our executive team. Prior to April 2023, Adam provided us with advisory services since our founding in 2019. Adam began his career with BP America as a completions engineer in 2005. During his tenure with BP America, Adam served in various drilling, completions, and production roles, both in the Gulf of Mexico and in the onshore U.S. business units. Following his experience at BP America, Adam transitioned to an equity analyst role within the Oil and Gas division at Macquarie Capital. After gaining experience on the financial services side of the oil and gas industry, Adam transitioned back to the operating side in a lead Petroleum Engineering role with then-start-up Halcón Resources Corporation (now Battalion Oil Corporation (NYSE: BATL) (“Halcón”)). While at Halcón, Adam supported various exploration and development programs in the broader Gulf Coast region and the Bakken shale asset in North Dakota. Following his tenure at Halcón, Adam pursued entrepreneurial opportunities on the mineral acquisitions side of the oil and gas industry that ultimately led him to us. Immediately prior to providing us advisory services, Adam was the Chief Executive Officer of The Petram Group, LLC (f/k/a Wolfhawk Energy Holdings, LLC d/b/a “Ferrari Energy”) (“The Petram Group”) from December 2016 until March 2019. Prior to his employment at The Petram Group, Mr. Ferrari founded and operated Ferrari Energy, LLC, which was active in acquiring and disposing of mineral interests from 2014 to 2017. In early 2016, Wolfhawk Energy Holdings, LLC (later to be renamed The Petram Group, LLC) began operating under the brand name “Ferrari Energy,” even though there was no formal connection between Ferrari Energy, LLC and Wolfhawk Energy Holdings, LLC. Currently, Ferrari Energy, LLC has no employees, holds only one remaining mineral property, and is otherwise inactive. Adam graduated magna cum laude from the University of Illinois at Urbana-Champagne with a Bachelor of Science Degree in Chemical Engineering. Adam Ferrari is the spouse of Brynn Ferrari, our Chief Marketing Officer, and the son of Charlene and Daniel Ferrari, who control LJC.
Curtis Allen. Curtis has been our Chief Financial Officer since February 2020, and a member of our board of directors since September 2025. Curtis is responsible for all accounting and finance functions and mineral underwriting, along with a multitude of day-to-day operational tasks. Curtis has over 15 years’ experience in financial services with an emphasis on investment analysis. Curtis has a range of accounting and financial experience, from a private tax practice to auditing billion-dollar defense contractors with the Department of Defense. Most recently, prior to joining the Company, Curtis spent over seven years managing investments for personal and corporate clients at
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LPL Financial. Curtis is a Certified Public Accountant, has held FINRA Series 7 and Series 66 licenses, and has passed the Chartered Financial Analyst Level I exam. Curtis graduated magna cum laude from the State University of New York at Oswego with both his Bachelor of Science and Master of Business Administration concentrated in Accounting.
David Scadden. David has been our Chief Operating Officer since November 2025. David previously served as our Chief Execution Officer since September 2024 and before that, as PhoenixOp’s Vice President of Drilling and Completions since February 2023. David is responsible for overseeing all of the operations of the business, including maintaining the reserves for all Phoenix Energy ownership. David has spent several years accumulating operational oil & gas experience throughout the American West, most recently serving as the Lead Drilling Engineer and Superintendent at Chord Energy from March 2021 to December 2022 and the Senior Drilling Engineer and Superintendent at Chord Energy prior to that. Mr. Scadden has served in roles spanning from onsite supervision to engineering management and has contributed to drilling projects in the San Juan Basin, Piceance Basin, Denver-Julesburg Basin, Eagle Ford Group, Granite Wash, and Williston Basin. David graduated from the University of Wyoming with a Bachelor of Science degree in Petroleum Engineering.
Lindsey Wilson. Lindsey has been our Chief Business Officer since December 2024. Prior to that time, Lindsey served as a Manager and as our Chief Operating Officer since she helped to found the Company in 2019. Lindsey is responsible for overseeing a wide range of business matters related to our operations and takes great pride in working with all of our departments on setting and achieving aggressive business goals. Lindsey brings to the Company years of extensive practical experience leading diverse, multidisciplinary teams in the energy sector. Lindsey entered the oil and gas industry in 2011 working leasing projects in Texas, and this foundational experience was the springboard that ultimately allowed her to transition into more advanced management roles within the mineral and leasehold acquisition space. From 2017 until immediately prior to helping found the Company, Lindsey was employed as the Operations Manager of The Petram Group. Lindsey graduated from the University of Texas at Arlington and holds a Bachelor of Business Administration with a concentration in Marketing.
Sean Goodnight. Sean has been our Chief Acquisitions Officer since June 2020. Sean brings over 25 years of consultative sales experience to the Company. Sean leads our acquisitions, securities, and sales efforts and has implemented processes, developed tools, and introduced materials that have contributed to the continued success of the Company. He has built a team of talented, sophisticated professionals who possess the expertise and skillset to maintain the high standards that have become the foundation of his department. Sean spent the early part of his career in the health care and insurance industries, and was introduced into the oil and gas industry in 2016 working with mineral acquisitions, where he quickly transitioned into management. Prior to joining the Company, Mr. Goodnight was employed by The Petram Group as an acquisitions landman from 2016 to 2018.
Justin Arn. Justin has been our Chief Land and Title Officer since April 2020. Justin began his Land career researching mineral and royalty rights for multiple mineral acquisition companies focusing on the Denver-Julesburg Basin in Weld County, Colorado, and Laramie County, Wyoming. He has coordinated and managed title projects, large and small, in Wyoming, Colorado, North Dakota, Montana, and Texas, and performed and managed opportunity and due diligence title work for the purchase of thousands of royalty acres throughout the Denver-Julesburg, Bakken, and Permian basins. Immediately prior to joining the Company, Justin was employed as a landman for The Petram Group from 2017 to 2020. Justin is an active member of the American Association of Professional Landmen and the Wyoming Association of Professional Landmen.
David Wheeler. David has been our Chief Legal Officer since October 2024 and is based out of our Irvine, California office. David is responsible for overseeing our day-to-day legal needs and providing advice and guidance to the management team on legal matters, including with respect to capital markets and securities laws and compliance, corporate structuring and governance, litigation management, and contract negotiation and drafting. David comes to us with over 20 years of legal experience as a corporate lawyer, serving most recently for over four years as the Chief Legal Officer of a private equity sponsored company with global operations operating in a regulated industry. Prior to that, David spent almost 13 years at Latham & Watkins LLP in their corporate department, advising both public and private clients on a wide variety of corporate law matters, including mergers and acquisitions, corporate governance, capital markets transactions, public company representation, and other general corporate and transactional matters. David graduated from The University of Southern California Gould School of Law with a Juris Doctorate and from Brigham Young University with a Bachelor of Science Degree in Business Management. David is actively licensed to practice law in the State of California.
Daniel Ferrari. Daniel has been a member and the chair of our board of directors since September 2025. Daniel is the founder and manager of LJC, the majority owner of Phoenix Equity. With a career spanning over four decades,
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Daniel brings extensive experience in public service, industrial operations, and entrepreneurship. From 1996 to 1999, Daniel worked with the Illinois Department of Corrections before concluding his public service career as a Juvenile Detention Specialist, retiring in 2016 due to a vaccine-related injury. Prior to that, Daniel was employed by the maintenance department of Mobil Oil Corporation for 17 years, gaining critical expertise in operational logistics and infrastructure management within the energy sector. Daniel graduated from Eastern Illinois University in 1972 with a Bachelor of Science in Business. Daniel is the father of our Chief Executive Officer, Adam Ferrari.
Jason Allan Pangracs. Jason has been a member of our board of directors since September 2025. Jason is Vice President and Chief Financial Officer for SSAB Americas division, a leading North American producer of steel plate and coil, with over 25 years of experience in the steel industry. Prior to his current position at SSAB Americas division, Jason served in the same company as its Controller of Value and Business Unit from October 2019 to July 2024, and held other positions at SSAB since 2008. Prior to joining SSAB, Jason was a senior accountant at KPMG LLP, in Canada, where he qualified as a Chartered Professional Accountant in 1998, and held that certification until 2022. Jason has been a Certified Public Accountant since 2001, and graduated from the University of Regina with Bachelor of Science degree in Business Administration. As a member of our board of directors Jason brings extensive experience in financial reporting, strategic planning and budgeting, restructuring and mergers and acquisitions. Jason is the brother-in-law of our Chief Executive Officer, Adam Ferrari.
Jason Montgomery Wagner. Jason has been a member of our board of directors and the chair and sole member of our audit committee since September 2025. Jason is a Managing Director at CBIZ CPAs P.C., a national recognized independent CPA firm, since January 2021, and previously served as partner in the accounting firms of Richey May and EKS&H. He has been a Certified Public Accountant since 1998. Jason also serves as a director CCI, Inc., a construction and engineering company active in the oil and gas industry, since 2018, and Pure Midstream Partners since 2024. Jason sits on the audit and compensation committees of CCI, Inc. He has extensive experience in transaction advisory services across a wide variety of other industries, including oil and gas. Jason serves and has served on a variety of boards, both profit and not-for profit. Mr. Wagner earned a bachelor’s degree in accounting at Oklahoma State University in 1993, and on full scholarship a master’s in taxation degree from the University of Denver in 1994.
Matthew Willer. Matthew has been serving as our Managing Director, Capital Markets, since March 2021. Matthew is responsible for investor relations and outreach and coordinating our investor presentations across our multiple debt offerings. Matthew is also the President and Director of M.D. Willer & Co., a boutique capital markets firm specializing in the needs of small-cap issuers, a position he has held since January 2002. Previously, Matthew co-founded Assure Holdings Corp., where he served as its President and Director from March 2016 to March 2018. Matthew received his Bachelor of Science in Finance and Management from the University of Southern California’s Marshall School of Business, with an emphasis on Finance and Management.
Family Relationships
Daniel Ferrari is the father of Adam Ferrari. Jason Allan Pangracs is the brother-in-law of Adam Ferrari. There are no other family relationships among any of our directors, director nominees, or executive officers.
Board Composition
We are a manager-managed limited liability company, and our business and affairs are managed under the direction of a board of directors. Our board of directors consists of five directors. Our Third ARLLCA provides that the board of directors shall consist of no fewer than one director and no more than seven directors, that the number of directors will be fixed from time to time by our board of directors, and that each director elected to our board of directors will serve for a one-year term or until his or her earlier death, resignation, disqualification, or removal.
Subject to the limited voting rights of the holders of the Series A Preferred Shares described in the Third ARLLCA, any of our directors may be removed with or without cause, by the affirmative vote of the holders of a majority of the voting power of the then-outstanding common shares, taken either at a shareholders meeting called for such purpose or by written or electronic consent. Our shareholders may act by written or electronic consent executed and delivered by shareholders holding at least the voting power necessary to approve such action. As of the date of this Annual Report, Phoenix Equity owns 100% of the outstanding common shares and thus may take action, including in respect of board composition matters, by written or electronic consent without a meeting of shareholders.
For the avoidance of doubt, if we do not pay distributions on the Series A Preferred Shares for six or more quarterly distribution periods (whether or not consecutive), the maximum number of directors will be automatically
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increased by two additional directors to serve on our board of directors until we pay, or declare and set aside funds for the payment of, all distributions that we owe on the Series A Preferred Shares, subject to certain limitations described in the Third ARLLCA.
Controlled Company and Status as a Company Listing Only Series A Preferred Shares
The rules of the NYSE American define a “controlled company” as a company in which more than 50% of the voting power is held by an individual, a group, or another company. Phoenix Equity holds all of our common shares, representing limited liability company interests, and, as a result, other than under the limited circumstances described in the Third ARLLCA in which holders of the Series A Preferred Shares have voting rights, Phoenix Equity has all of the voting power of the Company. As such, we are a “controlled company” under the rules of the NYSE American. As a result, we qualify for exemptions from, and have elected not to comply with, certain corporate governance requirements under the rules of the NYSE American, including the requirements that we have a board that is composed of a majority of “independent directors,” as defined under the rules, a nominating and corporate governance committee, or a compensation committee.
Even though we are a controlled company, we are required to comply with the rules of the SEC and the NYSE American relating to the membership, qualifications, and operations of the audit committee. The rules of the NYSE American provide that companies listing only preferred or debt securities on the NYSE American are only required to comply with the requirements to have a board that is composed of a majority of “independent directors,” an audit committee that is composed entirely of independent directors, an audit committee charter, and audit committee meeting requirements, responsibilities, and authorities, in each case, to the extent required by Rule 10A-3 under the Exchange Act. As a result, under these rules, we must have an audit committee of at least one director, which director must be independent. Our board of directors has affirmatively determined that Mr. Wagner, the chair and sole member of our audit committee, qualifies as an “independent director,” as defined under the Exchange Act and the rules of the NYSE American.
As a result of these reduced requirements, you will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE American, particularly with respect to the audit committee requirements set forth in the rules of the NYSE American. If we cease to be a controlled company and our Series A Preferred Shares continue to be listed on the NYSE American, we will be required to take all action necessary to comply with applicable rules, including by ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to specified transition periods applicable to certain requirements, as the case may be.
Board Committees
Our board of directors directs the management of our business and affairs and conducts its business through meetings of the board of directors and one standing committee—the audit committee—which has the composition and the responsibilities described below. In addition, from time to time, other or special committees may be established under the direction of our board of directors when necessary to address specific issues.
Audit Committee
Mr. Wagner is the sole member and chair of our audit committee, which is responsible for, among other things:
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Our board of directors has affirmatively determined that Mr. Wagner meets the definition of an “independent director” for purposes of serving on the audit committee under Rule 10A-3 and the rules of the NYSE American. In addition, our board of directors has determined that Mr. Wagner will qualify as an “audit committee financial expert,” as such term is defined in Item 407(d)(5) of Regulation S-K. The powers and responsibilities of our audit committee are more fully set forth in a written audit committee charter previously approved by our board of directors, which is available on our website under the “Investors—Corporate Governance” section at https://www.phoenixenergy.com.
Risk Oversight
Our board of directors is responsible for overseeing our risk management process. Our board of directors focuses on our general risk management strategy and the most significant risks facing us, and oversees the implementation of risk mitigation strategies by management. Our board of directors is also apprised of particular risk management matters in connection with its general oversight and approval of corporate matters and significant transactions.
Code of Ethics and Code of Conduct
We have adopted a Code of Business Conduct and Ethics that applies to all directors, officers, and employees of the Company, including the principal executive officer, the principal financial officer, and the principal accounting officer. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Investors—Corporate Governance” section at https://www.phoenixenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.
Insider Trading Policy
We have
A copy of our Insider Trading Policy is filed with this Annual Report as Exhibit 19.1.
Item 11. Executive Compensation
This compensation discussion and analysis discusses the material components and principles underlying the executive compensation program for our executive officers who are named in the Summary Compensation Table (as defined below). In 2025, our “named executive officers” and their positions were as follows:
The Company appointed Mr. Scadden as the Company’s Chief Operating Officer effective November 3, 2025 and on the same date, Mr. Allen resigned as the Company’s Chief Operating Officer.
Where relevant, the discussion below also reflects certain contemplated changes to our compensation structure that occurred after our 2025 fiscal year.
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Details of Our Compensation Program
Executive Compensation Philosophy and Objectives
Our compensation programs are designed to help achieve the goals of attracting, incentivizing, and retaining highly talented individuals who are committed to the Company, while balancing the long-term interests of our members, investors, and customers. The principles and objectives of our compensation and benefits program for our named executive officers are to:
Other than Mr. Ferrari and Mr. Brandon Allen, each of our named executive officers is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity, dated December 4, 2024 (as the same may be amended or supplemented from time to time, including on April 25, 2025, the “Phoenix Equity Operating Agreement”). Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our executive officers, are deemed to be a draw against and will reduce future distributions to the member with respect to such member’s membership interest in Phoenix Equity. Although Mr. Ferrari is not a member in Phoenix Equity, he holds 100% of the economic interests in LJC, and LJC is a member in Phoenix Equity. Under the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, commissions, or other cash compensation for services rendered, and the out-of-pocket costs incurred, by us for any health, welfare, retirement, fringe, or other similar benefits provided to Mr. Ferrari, whether such amounts are paid on, prior to, or following April 25, 2025, will reduce future distributions to LJC with respect to LJC’s membership interests in Phoenix Equity.
The base salary, variable revenue-based compensation, bonuses, and commission payment amounts for our named executive officers for 2025 were agreed upon by our named executive officers and the Company and are subject to change, in each case, as determined by our chief executive officer in consultation with or, with respect to Mr. Ferrari, the approval of, LJC.
Compensation Governance and Best Practices
We are committed to having strong governance standards with respect to our compensation programs, procedures, and practices. Our key compensation practices include the following:
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Determination of Compensation and Role of Executive Officers in Determining Executive Compensation
Our chief executive officer consulted with LJC and certain of our named executive officers to make compensation decisions with respect to our named executive officers for 2025. Ultimately, our chief executive officer, together with LJC, made 2025 compensation decisions for each of our named executive officers (other than Mr. Ferrari) based on their collective experience and knowledge of the compensation practices in our industry and that of similar companies within our industry. As described above, because any compensation payable to our named executive officers ultimately reduces each named executive officer’s future distributions payable with respect to his or her membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC), our named executive officers agree to their annual compensation packages. Mr. Ferrari’s 2025 compensation was determined by LJC with input from certain of the named executive officers based on the Company’s projected performance and an analysis of compensation practices within our industry.
Commencing in 2026, our board of directors makes compensation decisions in its sole discretion with respect to our named executive officers, including Mr. Ferrari. We do not currently have any plans to form a compensation committee or otherwise obtain third-party guidance regarding our compensation program.
Elements of Our Executive Compensation Program
We design the principal components of our executive compensation program to fulfill one or more of the principles and objectives described above. Compensation of any named executive officers consist of the following elements:
Our overall compensation program is designed to be flexible and complementary and to collectively serve all of the compensation objectives described above. Therefore, we do not currently have, and we do not expect to have, formal policies relating to the allocation of total compensation among the various elements of our compensation program.
Each of our named executive officers, other than Mr. Ferrari and Mr. Brandon Allen, is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Phoenix Equity Operating Agreement. Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, bonuses, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our named executive officers, are deemed to be a draw against and will reduce future distributions to the named executive officer with respect to such named executive officer’s membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC). Accordingly, base compensation, variable revenue-based compensation, bonuses, and commission payment amounts for 2025 were agreed upon by our named executive officers and our chief executive officer, in consultation with or, with respect to Mr. Ferrari, the approval of LJC. We continue to evaluate the mix of base compensation, bonuses, commissions, and equity-based compensation to appropriately align the interests of our named executive officers with those of our members and investors.
Base Compensation
Certain of our named executive officers receive a base salary determined by our chief executive officer in consultation with LJC and certain other executive officers. Base salary is a visible and stable fixed component of our compensation program. Base salaries for our named executive officers were initially established at the time each executive was hired and may be adjusted from time to time as determined by our chief executive officer based on the Company’s performance, market conditions, and individual performance and to be competitive within our market and industry.
Messrs. Ferrari and Curtis Allen and Ms. Wilson were entitled to receive variable revenue-based compensation for 2025 tied to revenue targets of the Company set by LJC, in lieu of a base salary.
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The following table sets forth the base compensation of our named executive officers for 2025:
Named Executive Officer |
|
2025 Annual |
|
Adam Ferrari |
|
$ |
7,425,000(1) |
Curtis Allen |
|
$ |
3,712,500(1) |
Sean Goodnight |
|
$ |
460,000(2) |
David Scadden |
|
$ |
565,000(2) |
Lindsey Wilson |
|
$ |
675,000(1) |
Brandon Allen |
|
$ |
575,000(2) |
For 2025, variable revenue-based compensation for Messrs. Ferrari and Curtis Allen and Ms. Wilson was tied to an assumed gross revenue target of $500.0 million set by LJC. No other revenue targets were used to determine the named executive officers’ 2025 variable revenue-based compensation. Messrs. Ferrari and Curtis Allen and Ms. Wilson were entitled to 1.10%, 0.55%, and 0.10% of our assumed 2025 gross revenue, respectively, upon achievement of the gross revenue target. Payments were made twice monthly throughout 2025 based on the assumed achievement of our revenue target with a final true-up payment at year end.
Our actual gross revenue for 2025 was $687.2 million.
We have not implemented formal agreements, policies, or other arrangements or mechanisms to facilitate recovery of variable revenue-based compensation paid to the named executive officers in the event actual revenue differs from an estimated or assumed level used to calculate the variable revenue-based compensation payments made to our named executive officers throughout the year or otherwise falls below an applicable revenue target. The appropriateness and manner of seeking any such recovery would be within the board of directors’ and (except as to his own compensation) Mr. Ferrari’s discretion, taking into account any factors that they determine are appropriate, including that, as discussed elsewhere in this compensation discussion and analysis, all compensation paid to Messrs. Ferrari and Curtis Allen and Ms. Wilson is a draw against, and will reduce, future distributions payable to the member with respect to such member’s membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC with respect to LJC’s interest in Phoenix Equity). Our board of directors and, for the named executive officers other than himself, Mr. Ferrari, have broad discretion to approve the compensation of our named executive officers on an annual basis and from time to time, and could account for such an event in a number of ways, including, for example, by updating the assumed level of revenue upon which semi-monthly payments are made during a year, or, to the extent any such difference is not reflected in the final true up payment for a given year, considering any overage amount when setting assumed revenue amounts, revenue sharing percentages, or annual discretionary bonuses for future years.
Bonuses
Our chief executive officer, in consultation with LJC, determined not to pay bonuses to any of our named executive officers for 2025.
Commissions
During 2025, Mr. Goodnight was eligible to receive sales commissions based on a percentage of the adjusted purchase price of mineral interests and interests in oil and gas properties that he is directly responsible for the Company acquiring in connection with our operations. Pursuant to the terms of the Commission Agreement by and between Mr. Goodnight and us, effective as of January 16, 2024 (the “Goodnight Commission Agreement”), Mr. Goodnight was eligible to earn a commission of 3.5% for closed mineral deals and 3.0% for closed lease deals during 2025. No such commissions were earned during 2025.
Equity Compensation
We view equity-based compensation as a critical component of our total compensation program. Equity-based compensation creates an ownership culture among our employees that provides an incentive to contribute to the continued growth and development of our business and aligns interests of executives with those of our members and investors. We do not currently have any formal policy for determining the number of equity-based awards to grant to named executive officers, but all named executive officers, along with all employees of the Company, are eligible for
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awards under our 2024 Long-Term Incentive Plan. We did not grant any equity-based awards to our named executive officers in 2025. The following discussion summarizes the material terms of the equity-based awards granted to certain of our named executive officers in previous years.
Each of our named executive officers other than Mr. Ferrari and Mr. Brandon Allen holds restricted units in Phoenix Equity. In addition, each of Mr. Curtis Allen and Ms. Wilson holds vested units in Phoenix Equity (the “retained units”). Mr. Brandon Allen was issued restricted units in Phoenix Equity in December 2024 but such restricted units were forfeited in connection with his departure from the Company in November 2025.
The restricted units held by our named executive officers are Class A Units and Class B Units in Phoenix Equity subject to restrictions on transferability as set forth in the Phoenix Equity Operating Agreement. In addition, as set forth in the applicable award agreement evidencing the issuance of the restricted units, the restricted units are subject to forfeiture in the event that such named executive officer ceases to be employed with Phoenix Equity and its subsidiaries prior to a change in control of Phoenix Equity. The restricted units are also subject to our repurchase rights under the Phoenix Equity Operating Agreement in the event of the named executive officer’s termination of employment for any reason other than upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement), except as set forth in an agreement between us and the named executive officer.
The retained units held by Mr. Curtis Allen and Ms. Wilson are fully vested Class A Units and Class B Units in Phoenix Equity that are not subject to forfeiture upon a termination of the named executive officer’s employment. In addition, as set forth in the applicable award agreement evidencing the issuance of the retained units, the retained units are not subject to repurchase by Phoenix Equity, and Phoenix Equity has also agreed that neither Mr. Curtis Allen nor Ms. Wilson will be subject to expulsion as a member of Phoenix Equity.
As of December 31, 2025, our named executive officers held the following number of Class A Units and Class B Units:
Name |
|
Restricted |
|
|
Vested |
|
|
Restricted |
|
|
Vested |
|
||||
Adam Ferrari |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Curtis Allen |
|
|
262,505 |
|
|
|
262,505 |
|
|
|
96,245 |
|
|
|
96,245 |
|
Sean Goodnight |
|
|
53,570 |
|
|
|
— |
|
|
|
210,930 |
|
|
|
— |
|
David Scadden |
|
|
53,570 |
|
|
|
— |
|
|
|
176,930 |
|
|
|
— |
|
Lindsey Wilson |
|
|
26,785 |
|
|
|
26,785 |
|
|
|
153,215 |
|
|
|
153,215 |
|
In addition to the Class A Units and Class B Units granted to Ms. Wilson in December 2024, Ms. Wilson was also entitled to receive a cash payment equal to $1,185,300 in lieu of any additional Class A Units or Class B Units she would otherwise have been entitled to as part of the conversion of her profits interests in Phoenix Equity to units in Phoenix Equity. Ms. Wilson received $150,000 of this amount in 2024 and received the remaining portion equal to $1,035,300 in 2025.
Retirement Savings and Health and Welfare Benefits
We currently maintain a 401(k) retirement savings plan for our employees, including our named executive officers, who satisfy certain eligibility requirements. Our named executive officers are eligible to participate in the 401(k) plan on the same terms as apply to our other employees generally. The U.S. Internal Revenue Code of 1986, as amended (the “Code”), allows eligible participants to defer a portion of their compensation, within prescribed limits, through elective contributions to the 401(k) plan. During the year ended December 31, 2025, we made company contributions to the 401(k) plan equal to 100.0% of elective contributions made by participants in the 401(k) plan, up to 4.0% of a participant’s eligible compensation which vest ratably over a three-year period.
All of our full-time employees, including our named executive officers, are eligible to participate in our health and welfare plans, including medical, dental, and vision benefits.
Perquisites and Other Personal Benefits
We did not provide any perquisites or special personal benefits to our named executive officers during 2025, but our board of directors may from time to time approve them in the future when it is determined that such perquisites are necessary or advisable to fairly compensate or incentivize our employees.
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Employment Arrangements
On May 8, 2025, we entered into a revised employee agreement with Mr. Ferrari, effective January 1, 2025, that provides that he will receive variable compensation based on a percentage of our assumed gross revenues, and that he is eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Ferrari’s variable compensation.
On May 8, 2025, we entered into a revised employee agreement with each of Mr. Curtis Allen and Ms. Wilson, effective January 1, 2025, that provides that each such named executive officer will receive variable compensation based on a percentage of our assumed gross revenues, and that they are eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Curtis Allen’s and Ms. Wilson’s variable compensation.
We entered into an offer letter with Mr. Goodnight in June 2020 in connection with his commencement of employment with the Company. Mr. Goodnight’s offer letter provides that his compensation package will be composed entirely of commission payments. In January 2024 we entered into the Goodnight Commission Agreement outlining the terms of Mr. Goodnight’s commission payments, as described above under “—Elements of Our Executive Compensation Program—Commissions.”
We also entered into an offer letter with Mr. Scadden in January 2023 in connection with his commencement of employment with the Company. Mr. Scadden’s offer letter sets forth the terms of his initial compensation package, including annual base salary, ability to receive additional discretionary bonuses based on the Company’s performance, and eligibility to participate in our employee benefit plans. In addition, in January 2025, we entered into an amendment to Mr. Scadden’s offer letter eliminating his ability to receive annual bonuses beginning in 2025 and providing that, effective for our 2025 fiscal year and future years, any salary changes and discretionary bonuses would be payable in the sole discretion of LJC.
Prior to his separation from employment, we were party to an offer letter with Mr. Brandon Allen, entered into in March 2023, in connection with his commencement of employment with the Company. Mr. Brandon Allen’s offer letter set forth the terms of his initial compensation package, including annual base salary, ability to receive additional discretionary bonuses based on the Company’s performance, and eligibility to participate in our employee benefit plans. In addition, in January 2025, we entered into an amendment to Mr. Brandon Allen's offer letter eliminating his ability to receive annual bonuses beginning in 2025 and providing that, effective for our 2025 fiscal year and future years, any salary changes and discretionary bonuses would be payable in the sole discretion of LJC. In November 2025, we entered into a Transition and Separation Agreement with Mr. Brandon Allen in connection with his departure from the Company. See “—Potential Payments Upon Termination or Change in Control of the Company” below for more information regarding this agreement.
Tax Considerations
As a general matter, our chief executive officer, in consultation with certain other executive officers and outside advisors, reviews and considers the various tax and accounting implications of compensation programs we utilize.
Compensation Policies
We do not currently maintain any formal compensation policies due to our governance structure and the nature in which compensation is mutually determined by our named executive officers and our chief executive officer in consultation with our board of directors (or previously, LJC).
Material Compensation Decisions Following December 31, 2025
On January 21, 2026, the Company entered into new employment agreements with each of Mr. Ferrari, Mr. Curtis Allen, and Ms. Wilson, in each case, effective January 1, 2026 (collectively, the “New Employment Agreements”) that superseded their prior employment agreements.
Pursuant to the New Employment Agreements with Messrs. Ferrari and Allen, each of Messrs. Ferrari and Allen continue to be entitled to receive variable revenue-based compensation for fiscal year 2026 tied to assumed gross revenue targets of the Company, equal to 0.9% and 0.45% of such assumed gross revenue, respectively. Payments of such variable compensation will be made twice monthly during fiscal year 2026 based on the assumed achievement of the revenue target, with a final true up payment to occur in December 2026.
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Pursuant to the New Employment Agreement with Ms. Wilson, Ms. Wilson is no longer entitled to receive the variable revenue-based compensation under her prior employment agreement but rather is entitled to receive base salary for fiscal year 2026 in the amount of $675,000. Ms. Wilson’s annual base salary may be changed by the Company from time to time upon notice to Ms. Wilson.
The New Employment Agreements were approved by the non-executive members of the board of directors of the Company in accordance with the Company’s governance policies currently in effect.
On January 27, 2026, the Company granted Mr. Scadden 75,000 phantom units pursuant to its 2024 Long-Term Incentive Plan and standard form of phantom unit award agreement. Such phantom units entitle Mr. Scadden to distribution equivalents, to the extent distributions are declared by the Company after the date of grant, and a cash payment upon a sale transaction based on the net proceeds received by the Company’s members, subject to vesting and other terms and conditions.
In January 2026, we increased the base salary of each of Mr. Goodnight and Mr. Scadden to $675,000 and $850,000, respectively, as determined by the board of directors.
Executive Compensation Tables
2025 Summary Compensation Table
The following table (the “Summary Compensation Table”) sets forth information concerning the compensation of our named executive officers for the year ended December 31, 2025:
Name and Principal Position |
|
Year |
|
Salary |
|
|
Bonus |
|
|
All Other |
|
|
Total |
|
||||
Adam Ferrari |
|
2025 |
|
|
7,425,000 |
|
|
|
— |
|
|
|
— |
|
|
|
7,425,000 |
|
Chief Executive Officer |
|
2024 |
|
|
3,135,000 |
|
|
|
— |
|
|
|
19,571 |
|
|
|
3,154,571 |
|
|
|
2023 |
|
|
408,334 |
|
|
|
— |
|
|
|
48,395 |
|
|
|
456,729 |
|
Curtis Allen |
|
2025 |
|
|
3,712,500 |
|
|
|
— |
|
|
|
2,400 |
|
|
|
3,714,900 |
|
Chief Financial Officer |
|
2024 |
|
|
1,567,500 |
|
|
|
— |
|
|
|
12,611 |
|
|
|
1,580,111 |
|
|
|
2023 |
|
|
360,355 |
|
|
|
— |
|
|
|
29,337 |
|
|
|
389,692 |
|
Sean Goodnight |
|
2025 |
|
|
460,000 |
|
|
|
— |
|
|
|
— |
|
|
|
460,000 |
|
Chief Acquisitions Officer |
|
2024 |
|
|
455,000 |
|
|
|
300,000 |
|
|
|
6,218 |
|
|
|
761,218 |
|
|
|
2023 |
|
|
483,402 |
|
|
|
— |
|
|
|
19,447 |
|
|
|
502,849 |
|
David Scadden |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Chief Operating Officer(4) |
|
2025 |
|
|
565,000 |
|
|
|
— |
|
|
|
103,404 |
|
|
|
668,404 |
|
Lindsey Wilson |
|
2025 |
|
|
675,000 |
|
|
|
— |
|
|
|
2,400 |
|
|
|
677,400 |
|
Chief Business Officer |
|
2024 |
|
|
399,000 |
|
|
|
32,000 |
|
|
|
16,189 |
|
|
|
447,189 |
|
|
|
2023 |
|
|
300,000 |
|
|
|
— |
|
|
|
38,453 |
|
|
|
338,453 |
|
Brandon Allen |
|
2025 |
|
|
492,436 |
|
|
|
— |
|
|
|
228,404 |
|
|
|
720,840 |
|
Former Chief Operating Officer(5) |
|
2024 |
|
|
300,000 |
|
|
|
225,000 |
|
|
|
9,583 |
|
|
|
534,583 |
|
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Outstanding Equity Awards at 2025 Fiscal Year-End
The following table sets forth certain information about restricted units granted to our named executive officers outstanding as of December 31, 2025:
|
|
Stock Awards |
|
|||||
Name |
|
Number of |
|
|
Market Value |
|
||
Adam Ferrari |
|
|
— |
|
|
$ |
— |
|
Curtis Allen |
|
262,505(2) |
|
|
$ |
17,089,076 |
|
|
|
|
96,245(3) |
|
|
$ |
6,265,550 |
|
|
Sean Goodnight |
|
53,570(2) |
|
|
$ |
3,487,407 |
|
|
|
|
210,930(3) |
|
|
$ |
13,731,543 |
|
|
David Scadden |
|
53,570(2) |
|
|
$ |
3,487,407 |
|
|
|
|
176,930(3) |
|
|
$ |
11,518,143 |
|
|
Lindsey Wilson |
|
26,785(2) |
|
|
$ |
1,743,704 |
|
|
|
|
153,215(3) |
|
|
$ |
9,974,297 |
|
|
Potential Payments Upon Termination or Change in Control
None of our named executive officers are entitled to cash severance or benefits upon his or her termination of employment for any reason, provided that the Company may determine to pay cash severance or grant severance benefits upon a named executive officer’s termination of employment in the discretion of our chief executive officer and/or our board of directors. We do not have a written or formal severance plan or policy that applies to any employees of the Company, including any of the named executive officers.
On November 20, 2025, the Company and Mr. Brandon Allen entered into a Transition and Separation Agreement (the “Separation Agreement”) in connection with Mr. Allen’s resignation from the Company on November 3, 2025 (the “Separation Date”). Pursuant to the Separation Agreement, Mr. Allen agreed to be engaged by the Company in a non-employee advisory capacity until the first anniversary of the Separation Date in order to facilitate an orderly transition of his duties and responsibilities. In consideration for such transition services and Mr. Allen’s execution, non-revocation, and compliance with the Separation Agreement, the Company agreed to pay Mr. Allen an amount equal to $1,000,000, payable in substantially equal installments over the 12-month period following the Separation Date in accordance with the Company’s normal payroll schedule. Pursuant to the pre-existing agreements governing Mr. Allen’s equity grants, all Class A and Class B Units previously issued to Mr. Allen by Phoenix Equity were forfeited for no consideration upon his Separation Date. The Separation Agreement includes a general release of claims by Mr. Allen in favor of the Company and its affiliates and contains non-disparagement, confidentiality, and cooperation provisions, along with reaffirmation of certain restrictive covenants under pre-existing agreements.
Upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement) the forfeiture and repurchase provisions applicable to the restricted Class A Units and restricted Class B Units held by any of our named executive officers will lapse.
For purposes of the restricted Class A Units and restricted Class B Units in Phoenix Equity, a “Liquidity Event” generally means the occurrence of one of the following:
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Assuming a Liquidity Event occurred as of December 31, 2025, the value received by each of our named executive officers in respect of their restricted Class A Units and restricted Class B Units would be:
Name |
|
Value of Class A |
|
|
Value of Class B |
|
||
Adam Ferrari |
|
$ |
— |
|
|
$ |
— |
|
Curtis Allen |
|
$ |
17,089,076 |
|
|
$ |
6,265,550 |
|
Sean Goodnight |
|
$ |
3,487,407 |
|
|
$ |
13,731,543 |
|
David Scadden |
|
$ |
3,487,407 |
|
|
$ |
11,518,143 |
|
Lindsey Wilson |
|
$ |
1,743,704 |
|
|
$ |
9,974,297 |
|
Director Compensation
Commencing in the fourth fiscal quarter of 2025, each of our non-executive directors became eligible to receive an annual cash retainer equal to $145,000 for their service on our board of directors. Additionally, each of our directors is eligible to be reimbursed for reasonable business expenses incurred in connection with his service on our board of directors.
2025 Director Compensation Table
The table below summarizes the total compensation for each of the non-executive directors in 2025. None of our non-executive directors held equity awards as of December 31, 2025.
Name |
|
Fees Earned or Paid in Cash ($) |
|
|
Total ($) |
|
||
Daniel Ferrari |
|
$ |
36,250 |
|
|
$ |
36,250 |
|
Jason Wagner |
|
$ |
36,250 |
|
|
$ |
36,250 |
|
Jason Pangracs |
|
$ |
36,250 |
|
|
$ |
36,250 |
|
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The table below sets forth, as of the date of this Annual Report, information regarding the beneficial ownership of Phoenix Equity’s outstanding membership interests and the Series A Preferred Shares by: (1) each person who is known to us to be the beneficial owner of 5% or more of Phoenix Equity’s outstanding membership interests; (2) each of our directors; (3) each of our named executive officers; and (4) all of our executive officers and directors as a group. The SEC has defined “beneficial ownership” of a security to mean the possession, directly or indirectly, of sole or shared voting power and/or investment power over such security, including options and warrants that are currently exercisable or exercisable within 60 days.
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Table of Contents
Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to the voting securities beneficially owned by them. Unless otherwise noted, the business address of the persons listed in the table below is 18575 Jamboree Road, Suite 830 Irvine, California 92612.
Name of Beneficial Holder |
|
Class A |
|
|
Class A |
|
|
Class B |
|
|
Class B |
|
|
Series A Preferred Shares(3) |
|
|
Series A Preferred Shares Percentage |
|
||||||
5% Holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lion of Judah Capital, LLC(4) |
|
|
1,100,000 |
|
|
|
56.5 |
% |
|
|
4,186,100 |
|
|
|
63.7 |
% |
|
|
— |
|
|
|
— |
|
Manager, Directors and Named Executive Officers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Adam Ferrari |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5,000 |
|
|
|
0.2 |
% |
Curtis Allen |
|
|
525,010 |
|
|
|
27.0 |
% |
|
|
192,490 |
|
|
|
2.9 |
% |
|
|
8,500 |
|
|
|
0.3 |
% |
Sean Goodnight |
|
|
53,570 |
|
|
|
2.8 |
% |
|
|
210,930 |
|
|
|
3.2 |
% |
|
|
500 |
|
|
* |
|
|
Lindsey Wilson |
|
|
53,570 |
|
|
|
2.8 |
% |
|
|
306,430 |
|
|
|
4.7 |
% |
|
|
500 |
|
|
* |
|
|
Brandon Allen |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
David Scadden |
|
|
53,570 |
|
|
|
2.8 |
% |
|
|
176,930 |
|
|
|
2.7 |
% |
|
|
— |
|
|
|
— |
|
Daniel Ferrari(4) |
|
|
1,100,000 |
|
|
|
56.5 |
% |
|
|
4,186,100 |
|
|
|
63.7 |
% |
|
|
— |
|
|
|
— |
|
Jason Allan Pangracs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,000 |
|
|
* |
|
|
Jason Montgomery Wagner |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
250 |
|
|
* |
|
|
All executive officers and directors as a group (nine individuals) |
|
|
1,785,720 |
|
|
|
91.7 |
% |
|
|
5,072,880 |
|
|
|
77.2 |
% |
|
|
16,750 |
|
|
|
0.5 |
% |
*Less than 0.1%
Item 13. Certain Relationships and Related Transactions, and Director Independence
In addition to the compensation arrangements, including employment, termination of employment, and change in control and indemnification arrangements, discussed in the section titled “Executive Compensation,” the following is a description of each transaction since January 1, 2023 and each currently proposed transaction in which:
Limited Liability Company Agreement of Phoenix Energy One, LLC
On January 23, 2025, we entered into the Second Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC (the “Second ARLLCA”), by and between ourselves and our sole member, Phoenix Equity.
During the period in which it was effective, the Second ARLLCA provided that Phoenix Equity was our sole member, entitled to 100% of any distributions made by us. The management of the Company was exclusively vested in Phoenix Equity and, as such, Phoenix Equity directed our business and operations, including appointment and compensation of our officers. The Second ARLLCA further provided that the managers of Phoenix Equity shall be deemed to be “managers” of the Company for all purposes under the DLLCA. LJC controls Phoenix Equity and, therefore, indirectly had control over the Company’s management. Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Adam Ferrari, our Chief Executive Officer, the
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Table of Contents
manager of Phoenix Equity, and the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC.
On September 30, 2025, in connection with the closing of our offering of Series A Preferred Shares, we amended and restated the Second ARLLCA and entered into the Third ARLLCA. For more information regarding the Third ARLLCA, see the “Description of Securities” filed with this Annual Report as Exhibit 4.1.
Investments in Company Debt
From time to time certain of our managers, directors or executive officers and their respective family members may purchase and hold our debt securities.
The following table sets forth, for the period from January 1, 2023 to December 31, 2025, investments made by such persons in our debt securities where such investments exceeded $120,000:
Related Party(1) |
|
Debt Security |
|
Interest Rate |
|
Principal |
|
|
Principal |
|
|
Principal |
|
|
Interest Paid |
|
||||
Adam Ferrari |
|
Adamantium Bonds |
|
15.0% |
|
$ |
2,287,000 |
|
|
$ |
2,287,000 |
|
|
$ |
— |
|
|
$ |
57,248 |
|
Adam Ferrari |
|
July 2022 506(c) Bonds |
|
8.0% - 11.0% |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
355,000 |
|
|
$ |
5,483 |
|
Adam Ferrari |
|
December 2022 506(c) Bonds |
|
9.0% - 12.0% |
|
$ |
1,027,000 |
|
|
$ |
— |
|
|
$ |
1,143,000 |
|
|
$ |
221,813 |
|
Adam Ferrari |
|
August 2023 506(c) Bonds |
|
13.0% - 14.0% |
|
$ |
3,397,000 |
|
|
$ |
— |
|
|
$ |
3,397,000 |
|
|
$ |
437,425 |
|
Adam Ferrari |
|
Reg A Bonds |
|
9.0% |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
135,000 |
|
|
$ |
4,215 |
|
Curtis Allen(3) |
|
Adamantium Bonds |
|
15.5% |
|
$ |
3,000,000 |
|
|
$ |
3,000,000 |
|
|
$ |
— |
|
|
$ |
38,750 |
|
Curtis Allen(3) |
|
December 2022 506(c) Bonds |
|
12.0% |
|
$ |
260,000 |
|
|
$ |
— |
|
|
$ |
386,000 |
|
|
$ |
28,668 |
|
Curtis Allen(3) |
|
August 2023 506(c) Bonds |
|
13.0% - 14.0% |
|
$ |
3,826,000 |
|
|
$ |
— |
|
|
$ |
3,826,000 |
|
|
$ |
305,784 |
|
Curtis Allen(3) |
|
Reg A Bonds |
|
9.0% |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
14,000 |
|
|
$ |
945 |
|
Lindsey Wilson |
|
December 2022 506(c) Bonds |
|
9.0% |
|
$ |
50,000 |
|
|
$ |
— |
|
|
$ |
50,000 |
|
|
$ |
4,690 |
|
Lindsey Wilson |
|
August 2023 506(c) Bonds |
|
13.0% |
|
$ |
410,000 |
|
|
$ |
306,000 |
|
|
$ |
104,000 |
|
|
$ |
41,988 |
|
Justin Arn |
|
December 2022 506(c) Bonds |
|
10.0% |
|
$ |
50,000 |
|
|
$ |
— |
|
|
$ |
50,000 |
|
|
$ |
5,236 |
|
Justin Arn |
|
August 2023 506(c) Bonds |
|
13.0% |
|
$ |
216,000 |
|
|
$ |
216,000 |
|
|
$ |
— |
|
|
$ |
49,581 |
|
Justin Arn |
|
Reg A Bonds |
|
9.0% |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
2,000 |
|
|
$ |
375 |
|
David Wheeler |
|
August 2023 506(c) Bonds |
|
12.0% |
|
$ |
179,000 |
|
|
$ |
179,000 |
|
|
$ |
— |
|
|
$ |
24,719 |
|
Jason Allan Pangracs |
|
August 2023 506(c) Bonds |
|
10.0% |
|
$ |
200,000 |
|
|
$ |
200,000 |
|
|
$ |
— |
|
|
$ |
46,667 |
|
Discretionary Payments
For the years ended December 31, 2025, 2024, and 2023, we paid interest expense of less than $0.1 million, less than $0.2 million, and less than $0.1 million, respectively, to a financial institution on behalf of LJC related to a certain financing agreement between LJC and this financial institution. Such payments were discretionary in nature, and we
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Table of Contents
are under no obligation to continue to make such payments on behalf of LJC. For the year ending December 31, 2026, we expect to make additional payments up to an amount equal to approximately $0.1 million.
Indemnification of Directors and Officers
We have entered into indemnification agreements with each of our directors and executive officers. These agreements require us to indemnify these individuals to the fullest extent permitted under the DLLCA against expenses, losses, and liabilities that may arise in connection with actual or threatened proceedings in which they are involved by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified.
The Third ARLLCA provides that we will indemnify our members and executive officers, to the fullest extent permitted by law, from any liability, loss, or damage incurred by any member or officer or by reason of any act performed or omitted to be performed by any member or officer in connection with our business, subject to certain exceptions.
Related Persons Transaction Policy
We have adopted a related person transaction policy which covers, with certain exceptions set forth in Item 404 of Regulation S-K under the Securities Act, any transaction, arrangement, or relationship, or any series of similar transactions, arrangements, or relationships, in which we were or are to be a participant, where the amount involved exceeds $120,000 in any fiscal year and in which a related person had, has, or will have a direct or indirect material interest. Our related person policy does not specify the standards to be applied by our board of directors (or the disinterested directors or any committee thereof) in determining whether or not to approve or ratify a related person transaction, and accordingly these determinations will be made in accordance with the principles of Delaware law generally applicable to managers of a Delaware limited liability company and the terms of the Third ARLLCA.
Pursuant to this revised related person transaction policy, if a member of our board of directors is a party to a transaction to be voted on, he or she will not vote on the approval of the transaction.
Generally, our board of directors will review all transactions, activities, arrangements, circumstances, or other matters between or among one or more related parties, on the one hand, and us, on the other hand, including those transactions that are required to be disclosed in any proxy statement we may prepare or in the notes to our audited financial statements. A “related party” includes any executive officer, director, nominee for director, or beneficial holder of more than 5% of our or Phoenix Equity’s outstanding membership interests, any immediate family member of those persons, and any entity that is owned or controlled by any of the foregoing persons or any entity in which such a person is an executive officer.
Our board of directors have the power and authority, in its sole discretion, to retain or obtain the advice of any financial advisors, consultants, legal counsel, or other advisors in connection with conducting investigations into or studies of related party transactions. In addition, our board of directors is able to ask members of management or others to attend its meetings and to provide pertinent information as necessary.
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Table of Contents
Item 14. Principal Accounting Fees and Services
The following table sets forth information regarding the fees billed to the Company by the Company’s independent registered public accounting firm, Ramirez Jimenez International CPAs, for the fiscal years ended December 31, 2025 and 2024:
|
|
Year Ended December 31, |
|
|||||
(in thousands) |
|
2025 |
|
|
2024 |
|
||
Audit fees(1) |
|
$ |
961 |
|
|
$ |
1,014 |
|
Audit-related fees(2) |
|
|
141 |
|
|
|
197 |
|
All other fees(3) |
|
|
— |
|
|
|
3 |
|
Total fees |
|
$ |
1,102 |
|
|
$ |
1,214 |
|
Our audit committee was established on September 29, 2025. It is our audit committee’s policy to pre-approve all audit, audit-related, and permissible non-audit services rendered to us by our independent auditor. Consistent with such policy, following the establishment of our audit committee, all such services provided by, and all fees of, our independent auditor were pre-approved by our audit committee.
164
Table of Contents
PART IV
Item 15. Exhibits and Financial Statement Schedules
Exhibit Index
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
|
|
|
|
|
|
|
|
|
|
|
3.1 |
|
Certificate of Formation of Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), dated as of April 16, 2019. |
|
S-1 |
|
10/29/2024 |
|
3.1 |
|
|
3.2 |
|
Certificate of Amendment to the Certificate of Formation of Phoenix Energy One, LLC, dated as of January 23, 2025. |
|
S-1/A |
|
03/28/2025 |
|
3.2 |
|
|
3.3 |
|
Third Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC. |
|
8-K |
|
09/30/2025 |
|
3.1 |
|
|
3.4 |
|
Phoenix Energy One, LLC Share Designation with Respect to the Series A Cumulative Redeemable Preferred Shares. |
|
8-K |
|
09/30/2025 |
|
3.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1 |
|
Description of Securities. |
|
|
|
|
|
|
|
* |
4.2 |
|
Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated May 14, 2025, governing the Registered Notes. |
|
10-Q |
|
05/16/2025 |
|
4.1 |
|
|
4.3 |
|
Form of Cash Interest Note (included in Exhibit 4.2). |
|
10-Q |
|
05/16/2025 |
|
4.2 |
|
|
4.4 |
|
Form of Compound Interest Note (included in Exhibit 4.2). |
|
10-Q |
|
05/16/2025 |
|
4.3 |
|
|
4.5 |
|
First Supplemental Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated March 17, 2026, governing the Registered Notes. |
|
|
|
|
|
|
|
* |
4.6 |
|
Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of January 12, 2022, governing the Reg A Bonds. |
|
S-1 |
|
10/29/2024 |
|
4.4 |
|
|
4.7 |
|
First Supplemental Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of February 1, 2022. |
|
S-1 |
|
10/29/2024 |
|
4.5 |
|
|
4.8 |
|
Second Supplemental Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of July 18, 2022. |
|
S-1 |
|
10/29/2024 |
|
4.6 |
|
|
4.9 |
|
Third Supplemental Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of May 25, 2023. |
|
S-1 |
|
10/29/2024 |
|
4.7 |
|
|
4.10 |
|
Form of Reg A Bond. |
|
S-1 |
|
10/29/2024 |
|
4.8 |
|
|
4.11 |
|
Form of Adamantium Bond. |
|
S-1 |
|
10/29/2024 |
|
4.9 |
|
|
4.12 |
|
Form of July 2022 506(c) Bond. |
|
S-1 |
|
10/29/2024 |
|
4.11 |
|
|
4.13 |
|
Form of December 2022 506(c) Bond (Series AAA through Series D-1). |
|
S-1 |
|
10/29/2024 |
|
4.12 |
|
|
4.14 |
|
Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of August 25, 2023, governing the August 2023 506(c) Bonds. |
|
S-1 |
|
10/29/2024 |
|
4.13 |
|
|
4.15 |
|
Form of August 2023 506(c) Bond (Series U through Series Z-1). |
|
S-1 |
|
10/29/2024 |
|
4.14 |
|
|
4.16 |
|
First Supplemental Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of August 20, 2024. |
|
S-1 |
|
10/29/2024 |
|
4.15 |
|
|
165
Table of Contents
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
4.17 |
|
Form of August 2023 506(c) Bond (Series AA through Series JJ-1) (included in Exhibit 4.16). |
|
S-1 |
|
10/29/2024 |
|
4.16 |
|
|
4.18 |
|
Second Supplemental Indenture, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and UMB Bank, N.A., as trustee, dated as of October 17, 2024. |
|
S-1 |
|
10/29/2024 |
|
4.17 |
|
|
4.19 |
|
Third Supplemental Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated as of May 14, 2025, governing the August 2023 506(c) Bonds. |
|
10-Q |
|
05/16/2025 |
|
4.18 |
|
|
4.20 |
|
Fourth Supplemental Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated as of March 16, 2026, governing the August 2023 506(c) Bonds. |
|
|
|
|
|
|
|
* |
4.21 |
|
Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated as of May 15, 2025, governing the Exchange Notes. |
|
10-Q |
|
05/16/2025 |
|
4.19 |
|
|
4.22 |
|
Form of Cash Interest Note (included in Exhibit 4.21). |
|
10-Q |
|
05/16/2025 |
|
4.20 |
|
|
4.23 |
|
Form of Compound Interest Note (included in Exhibit 4.21). |
|
10-Q |
|
05/16/2025 |
|
4.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1†++ |
|
Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity Holdings, LLC, dated as of December 4, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.4 |
|
|
10.2†++ |
|
First Amendment to the Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity Holdings, LLC, dated as of April 25, 2025. |
|
S-1/A |
|
04/25/2025 |
|
10.30 |
|
|
10.3† |
|
Employee Agreement, by and between Phoenix Energy One, LLC and Curtis Allen, effective as of January 1, 2026. |
|
8-K |
|
01/21/2026 |
|
10.2 |
|
|
10.4†++ |
|
Unit Award Agreement, by and between Phoenix Equity Holdings, LLC and Curtis Allen, dated as of December 4, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.5 |
|
|
10.5†++ |
|
Employee Offer Letter, by and between Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC) and Sean Goodnight, dated as of June 12, 2020. |
|
S-1/A |
|
03/28/2025 |
|
10.7 |
|
|
10.6†++ |
|
Unit Award Agreement, by and between Phoenix Equity Holdings, LLC and Sean Goodnight, dated as of December 4, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.6 |
|
|
10.7† |
|
Commission Agreement, by and between Phoenix Energy One (f/k/a Phoenix Capital Group Holdings, LLC) and Sean Goodnight, dated as of January 16, 2024. |
|
S-1/A |
|
03/28/2025 |
|
10.13 |
|
|
10.8† |
|
Employee Agreement, by and between Phoenix Energy One, LLC and Adam Ferrari, effective as of January 1, 2026. |
|
8-K |
|
01/21/2026 |
|
10.1 |
|
|
10.9† |
|
Employee Agreement, by and between Phoenix Energy One, LLC and Lindsey Wilson, effective as of January 1, 2026. |
|
8-K |
|
01/21/2026 |
|
10.3 |
|
|
10.10† |
|
Employee Offer Letter, by and between Phoenix Operating LLC and Brandon Allen, dated as of March 2, 2023. |
|
S-1/A |
|
03/28/2025 |
|
10.11 |
|
|
10.11† |
|
Performance Bonus Amendment, by and among Phoenix Operating LLC, Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), and Brandon Allen, dated as of January 22, 2025. |
|
S-1/A |
|
03/28/2025 |
|
10.12 |
|
|
10.12 |
|
Transition and Separation Agreement, by and between Phoenix Energy One, LLC and Brandon K. Allen, dated as of November 20, 2025. |
|
8-K |
|
11/25/2025 |
|
10.1 |
|
|
10.13† |
|
Employee Agreement, by and between Phoenix Operating, LLC and David Scadden, effective as of January 13, 2023. |
|
|
|
|
|
|
|
* |
166
Table of Contents
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
10.14†
|
|
Performance Bonus Amendment, by and among Phoenix Operating LLC, Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), and David Scadden, dated as of January 22, 2025. |
|
|
|
|
|
|
|
* |
10.15† |
|
2024 Long-Term Incentive Plan of Phoenix Equity Holdings, LLC. |
|
S-1/A |
|
12/30/2024 |
|
10.20 |
|
|
10.16† |
|
Form of Unit Award Agreement of Phoenix Equity Holdings, LLC. |
|
S-1/A |
|
12/30/2024 |
|
10.21 |
|
|
10.17† |
|
Form of Phantom Unit Award Agreement of Phoenix Equity Holdings, LLC. |
|
S-1/A |
|
12/30/2024 |
|
10.22 |
|
|
10.18 |
|
Form of Indemnification Agreement. |
|
8-K |
|
09/30/2025 |
|
10.1 |
|
|
10.19† |
|
Form of Non-Employee Director Compensation Letter. |
|
8-K |
|
09/30/2025 |
|
10.2 |
|
|
10.20 |
|
Loan Agreement, by and between Adamantium Capital LLC and Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), dated as of September 14, 2023. |
|
S-1 |
|
10/29/2024 |
|
10.10 |
|
|
10.21 |
|
Loan Agreement Amendment and Note Modification Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, and Adamantium Capital LLC, dated as of October 30, 2023. |
|
S-1 |
|
10/29/2024 |
|
10.11 |
|
|
10.22 |
|
Second Amendment to Loan Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, and Adamantium Capital LLC, dated as of December 12, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.19 |
|
|
10.23 |
|
Third Amendment to Loan Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, and Adamantium Capital LLC, dated as of January 3, 2025. |
|
S-1/A |
|
03/29/2025 |
|
10.27 |
|
|
10.24 |
|
Fourth Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of January 24, 2025. |
|
S-1/A |
|
03/29/2025 |
|
10.28 |
|
|
10.25 |
|
Fifth Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of October 6, 2025. |
|
8-K |
|
11/12/2025 |
|
10.5 |
|
|
10.26 |
|
Sixth Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of February 12, 2026. |
|
|
|
|
|
|
|
* |
10.27 |
|
Seventh Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of March 16, 2026. |
|
|
|
|
|
|
|
* |
10.28++
|
|
Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of August 12, 2024. |
|
S-1 |
|
10/29/2024 |
|
10.14 |
|
|
10.29++ |
|
Limited Waiver and Amendment No. 1 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of October 25, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.16 |
|
|
10.30++ |
|
Amendment No. 2 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC (f/k/a |
|
S-1/A |
|
12/30/2024 |
|
10.17 |
|
|
167
Table of Contents
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
|
|
Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of November 1, 2024. |
|
|
|
|
|
|
|
|
10.31++ |
|
Amendment No. 3 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of December 18, 2024. |
|
S-1/A |
|
12/30/2024 |
|
10.18 |
|
|
10.32++ |
|
Limited Waiver and Amendment No. 4 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of April 16, 2025. |
|
S-1/A |
|
04/25/2025 |
|
10.29 |
|
|
10.33++ |
|
Amendment No. 5 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of June 26, 2025. |
|
1-A |
|
06/26/2025 |
|
6.34 |
|
|
10.34++ |
|
Amendment No. 6 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of August 1, 2025. |
|
8-K |
|
08/01/2025 |
|
10.1 |
|
|
10.35++ |
|
Amendment No. 7 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of October 27, 2025. |
|
8-K |
|
10/27/2025 |
|
10.1 |
|
|
10.36++ |
|
Amendment No. 8 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of February 12, 2026. |
|
8-K |
|
02/13/2026 |
|
10.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
19.1 |
|
Phoenix Energy One, LLC Insider Trading Policy. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
21.1 |
|
List of Subsidiaries of the Registrant. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
31.1 |
|
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
* |
31.2 |
|
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
32.1 |
|
Certifications of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
** |
32.2 |
|
Certifications of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
** |
|
|
|
|
|
|
|
|
|
|
|
97.1 |
|
Phoenix Energy One, LLC Policy for Recovery of Erroneously Awarded Compensation. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
168
Table of Contents
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
101.INS |
|
Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
|
|
|
|
|
|
|
* |
101.SCH |
|
Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
104 |
|
The cover page for the Company's Annual Report on Form 10-K has been formatted in Inline XBRL and contained in Exhibit 101. |
|
|
|
|
|
|
|
* |
++ Certain annexes, schedules, and exhibits to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby agrees to furnish supplementally a copy of any omitted annex, schedule, or exhibit to the SEC upon request.
† Management contract or compensatory plan or arrangement.
* Filed herewith.
** Furnished herewith.
169
Table of Contents
Item 16. Form 10-K Summary
None.
170
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
PHOENIX ENERGY ONE, LLC |
|
|
|
|
|
Date: March 17, 2026 |
|
By: |
/s/ Curtis Allen |
|
|
|
Curtis Allen |
|
|
|
Chief Financial Officer |
Pursuant to the requirements of the Securities and Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature |
Title |
Date |
/s/ Adam Ferrari |
Chief Executive Officer and Director |
March 17, 2026 |
Adam Ferrari |
(principal executive officer) |
|
|
|
|
/s/ Curtis Allen |
Chief Financial Officer and Director |
March 17, 2026 |
Curtis Allen |
(principal financial officer and principal accounting officer) |
|
|
|
|
/s/ Daniel Glen Ferrari, by Charlene Ferrari, POA |
Director |
March 17, 2026 |
Daniel Ferrari |
|
|
|
|
|
/s/ Jason Allan Pangracs |
Director |
March 17, 2026 |
Jason Allan Pangracs |
|
|
|
|
|
/s/ Jason Montgomery Wagner |
Director |
March 17, 2026 |
Jason Montgomery Wagner |
|
|
|
|
|
171
