NYSE: PHXE-P

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,

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

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.”

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:

Our specialized software provides market intelligence to identify and rank potential assets and support our acquisition strategy and functions.

We make contact with the owner of the asset and begin the conversation on how we can increase the value of the property for the owner.

We provide the potential seller with a packet detailing our business, industry data, property valuation, and an all-cash offer based on the valuation.

Our sales team engages the potential seller to discuss the terms of the sale and the value of the property.

We handle the closing of the property and the property is migrated to our portfolio.

We utilize our land rights to extract natural resources from the property through third-party operators or determine to proceed with our own direct drilling operations.

We collect a portion of the revenue generated from the natural resources extracted and sold by a third-party operator. Our share of the revenue depends on the type of asset, either mineral rights or non-operated working interests, and the underlying contract with the third-party operator.

We continue to operate the property to extract the minerals through third-party operators or PhoenixOp until we decide to sell the property rights.

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:

Asset Discovery – The data-driven system has customized inputs that are selected by management to pull in and incorporate data sets from multiple third-party sources through custom application interfaces that automatically retrieve updated information on a regular basis. For example, the system retrieves detailed land and title data and well-level data, including operator, production metrics, well status, dates of activities, well-specific activities, and historical reporting. The software system compiles these inputs and creates dashboards that can be accessed by management to analyze and review granular data on an asset-by-asset level. These dashboards present certain key information, including, among others, the geography of the asset, the estimated probability of future oil wells, the estimated predictability of the timing and value of cash flows, and local and national oil prices. We believe this process provides us with key market intelligence and insights, tailored to prioritize asset traits curated and targeted by management, to identify and rank potential assets. We believe this provides us with a competitive advantage because we are able to identify potentially valuable assets, based on our own hierarchy and prioritization of asset traits and data inputs, that may otherwise be overlooked by other industry participants.

Asset Grading and Estimates – The outputs from the asset discovery process are then run through a discounted cash flow model, using management inputs for discount rate and the price of oil, to generate asset value and pricing estimates. The software system grades these assets based on management’s desired target criteria for high probability of high near-term cash flow, and generates a summary version of assets to prospect for acquisition for our sales team. The system also generates an acquisition price for each asset, which informs the sales team as to the maximum price that we may be willing to offer in any prospective transaction. This process is used to further characterize high-priority targets for sales and acquisition efforts.

Asset Acquisition – Based on management input, the software system then routes the pricing and asset information from the asset grading and estimates process through an automated document generator to create customized, asset-specific document packages for utilization and distribution by our sales team. The workflow for these document packages is then processed and monitored using our internally developed software, which distributes the documents to our operations team for the preparation of an offering and sale package, which is then delivered to the prospective seller. Using relationship management features within our internally developed software, the sales team is able to record notes and each opportunity can be tracked from its original data upload through the lifecycle of the sales process.

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.

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:

Well Count

Oil

Gas

Gross

Net

Gross

Net

Basin or Producing Region

Bakken/Williston Basin

4,537

120.2

3

0.0

Denver-Julesburg Basin/Rockies/Niobrara

1,495

17.7

6

0.0

Permian Basin

740

1.4

1

0.0

Other

492

1.3

494

2.6

Total

7,264

140.6

504

2.6

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

Net Royalty Acres

Developed

Acreage

Undeveloped

Acreage

Total

Acreage

Basin

Bakken/Williston Basin

23,637

83,596

107,233

Denver-Julesburg Basin/Rockies/Niobrara/PRB

5,398

12,526

17,924

Permian Basin

657

354

1,011

Other

470

435,680

436,150

Total Net Royalty Acres

30,162

532,156

562,318

Gross Royalty Acres

Developed

Acreage

Undeveloped

Acreage

Total

Acreage

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

Acreage

Undeveloped

Acreage

Total

Acreage

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

Gross Mineral Acres

Developed

Acreage

Undeveloped

Acreage

Total

Acreage

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

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

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:

review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;

preparation of reserves estimates by Brandon Allen (prior to his departure) and Kyle Beam or under their direct supervision;

review by Brandon Allen (prior to his departure), Kyle Beam, and Curtis Allen, our Chief Financial Officer, of all of our reported proved and probable reserves at the close of the calendar year, including the review of all significant reserve changes and all new proved and probable undeveloped reserves additions;

verification of property ownership by our land department; and

no employee’s compensation being tied to the amount of reserves booked.

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

(1)
Estimates of reserves of oil and natural gas as of December 31, 2025 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2025, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $66.01 per Bbl for oil and $3.387 per MMBtu for natural gas at December 31, 2025. Estimates of reserves of NGL as of December 31, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2025 was $20.90 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2)
In early 2023, PhoenixOp was established with the intention that certain leaseholds held by us would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company on June 20, 2023. This allowed for previously unbooked reserves as of December 31, 2022 to be estimated and booked as of December 31, 2023 as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth in Rule 4-10(a)(31) of Regulation S-X.

(3)
Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(4)
Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(5)
Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended December 31, 2025 was used, the conversion factor would be approximately 19.5 Mcf per Bbl of oil.

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

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

%

(1)
“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

(2)
Operating costs per Boe increased in 2025 primarily due to (i) the increased proportion of operated production as compared to royalty production, which carries higher direct operating expenses, (ii) inflationary pressures on field services and disposal costs, and (iii) the integration of newly developed wells into our production base. We expect unit costs to moderate over time as operated production scales and fixed field-level costs are absorbed across a larger production base.

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.

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.

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.

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.

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.

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

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

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

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.

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:

the location of wells;

the method of drilling and casing wells;

the timing of construction or drilling activities, including seasonal wildlife closures;

the rates of production or “allowables”;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to, and consultation with, surface owners and other third parties.

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

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

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

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.