WhiteHawk Minerals Corp.: Form 10-Q for the period ended Jun 30, 2026

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Registration Statement on Form S-1/A filed with the SEC on June 5, 2026.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are based on our current expectations about future events and can be identified by terms such as “believe,” “anticipate,” “may,” “might,” “will,” “intend,” “should,” “could,” “would,” “expect,” “estimate,” “predict,” “project,” “plan,” “potential,” “seek,” “forecast” or similar expressions and the negatives of those terms. Forward-looking statements include, but are not limited to, statements regarding:

• our business strategy, including anticipated trends and developments in and management plans for our business and the markets in which we operate;
• our future financial position, production, reserves, cash flows, revenues, costs, capital expenditures and ability to pay dividends;
• our acquisition strategy, including our ability to identify and complete acquisitions, successfully integrate acquired assets, and constraints in our ability to finance acquisitions;
• the development and drilling activity by operators on our acreage and our reliance on third-party operators to develop our properties;
• oil, natural gas and natural gas liquids prices and the volatility thereof, which may result in impairment charges;
• our derivative activities and their potential to limit cash flows from natural gas and oil sales;
• drilling and production risks and uncertainties, including title defects or other issues in our properties;
• concentration of revenue and accounts receivable with a limited number of third-party operators and geographic concentration in the Appalachian and Haynesville Basins;
• our ability to retain key personnel and attract additional qualified personnel;
• our estimated proved reserves and identified drilling locations, which are based on assumptions and susceptible to uncertainties;
• information technology system failures, network disruptions, cyber-attacks or breaches in data security;
• declining general economic, business or industry conditions and competitive pressures;
• our growth strategy and its dependence on continued expansion of electricity demand driven by AI data center development;
• unavailability, high cost or shortages of equipment, raw materials, supplies, personnel or transportation facilities;
• governmental regulations, permit delays or denials, and changes in legal requirements that could restrict operations or increase costs;
• climate change legislation, sustainability initiatives, and other environmental regulations that may impact our business or the business of our third-party operators;
• our use of borrowings to finance our business and the risks associated with our indebtedness;
• anti-takeover provisions in our governing documents and Delaware law that may have the effect of delaying or preventing a change of control;
• our ability to pay regular dividends to our stockholders;
• the requirements of being a public company and their effect on our resources and ability to attract and retain qualified board members and officers;
• the effectiveness of our disclosure controls and procedures and internal control over financial reporting; and
• our ability to remediate the material weaknesses in our internal control over financial reporting.

These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including those described in “Risk Factors” in Part II, Item 1A of this Quarterly Report and in our Registration Statement on Form S-1/A (File No. 333-295743) filed with the SEC on June 5, 2026. The forward-looking statements contained in this Quarterly Report are based on our current expectations as of the date of this filing, and we assume no obligation to update or revise any forward-looking statements to reflect new information or circumstances, except as required by law.

Overview

We are focused on being the premier natural gas mineral and royalty business in the United States. We are committed to delivering cash flow and total returns to our investors through the disciplined acquisition, active management and ownership of high-quality mineral and royalty interests. Our assets are concentrated in the Marcellus and Haynesville Shales, which are located in the Appalachian and Haynesville Basins, among the most productive and lowest-cost natural gas basins in the United States. We own the largest, high-quality publicly traded natural gas mineral portfolio in the United States. As a mineral and royalty business, we do not pay any drilling-related capital expenditures and only minimal operating expenses on our properties. This results in a high-margin business and allows us to distribute a meaningful portion of our cash flow to investors, while providing them with potential for significant capital appreciation over time.

Recent Developments

On June 9, 2026, the Company consummated an IPO of 8,479,532 Class A Common Stock at $26.00 per share, which includes the partial exercise of the underwriters’ over-allotment option of 779,532 Class A Common Stock, generating gross proceeds of $220.5 million. Transaction costs amounted to $21.7 million, consisting of $15.4 million of underwriting fees and $6.3 million of other offering costs.

In conjunction with the IPO, the Company entered into a Contribution Agreement the Management Contributor for the contribution of all of the outstanding interests in ManagementCo to OpCo in exchange for OpCo Interests for a total purchase price of $130.0 million. After the closing of the Internalization, Management Co has become a wholly owned subsidiary of OpCo and includes the personnel that has historically managed our business on behalf of ManagementCo. The Company is now internally managed and operated by our executive officers and other employees.

In March 2026, the Company entered into a definitive purchase and sale agreement to acquire natural gas mineral and royalty interests primarily located in the Haynesville Shale in Louisiana and East Texas for approximately $33.0 million. The transaction closed in April 2026.

In August 2026, the Company signed a definitive purchase and sale agreement with San Jacinto Minerals II ("SJM II") to acquire natural gas mineral and royalty interests in the core of Appalachia and Haynesville minerals for approximately $105.0 million. The transaction is expected to close in September 2026.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below.

Corporate Reorganization

In connection with the completion of the IPO, we amended and restated our certificate of incorporation to, among other things, change our name to “WhiteHawk Minerals Corp.”; effect the common stock reclassification; adjust our authorized capital stock to 250,000,000 shares of Class A common stock, 100,000,000 shares of Class B common stock and 10,000,000 shares of preferred stock, each par value $0.0001 per share; authorize our board of directors to establish and fix the terms of one or more series of preferred stock; and create Class B common stock in connection with our Up-C structure, to be issued to holders of OpCo Interests, with each share entitled to one vote and no economic rights. OpCo entered into the Amended and Restated Limited Partnership Agreement, dated June 10, 2026 (the “OpCo Agreement”), to, among other things, appoint WhiteHawk Income OP GP LLC (“OP GP”) as sole general partner with authority to manage OpCo’s business and affairs. To effectuate the Internalization, the Company, WhiteHawk OpCo, the Management Contributor and ManagementCo entered into the Contribution Agreement, dated June 9, 2026, pursuant to which OpCo acquired all outstanding equity interests in ManagementCo from the Management Contributor in exchange for OpCo Interests and shares of Class B common stock; as a result, ManagementCo became a wholly owned subsidiary of OpCo and we became internally managed. We issued 8,479,532 shares of our Class A common stock in the IPO at an initial public offering price of $26.00 per share, generating net proceeds of approximately $198.8 million. As a result of the Internalization, we expect a meaningful reduction in our operating expenses due to the elimination of management fees and other costs previously paid to ManagementCo.

Acquisitions

Our financial statements for the year ended December 31, 2025 do not include the results of operations for the Three Rivers Acquisition or the PHX Merger prior to the respective dates of acquisition. As a result, our financial results do not give an accurate indication of what the actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be. For additional discussion of the Three Rivers Acquisition and the PHX Merger. Acquisitions are an important part of our growth strategy, and we plan to pursue potential accretive acquisitions of additional natural gas-weighted mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically accretive terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to stockholders in the short term.

Public Company Expenses

As a result of the IPO, we are incurring incremental G&A expenses as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, increased independent auditor fees, increased independent reserve engineer fees, increased legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. Additionally, we may hire additional employees, including accounting, engineering, land and legal personnel, in order to comply with requirements of being a publicly traded company.

Management Fees

The Company incurred and paid fees under the amended and restated investment management agreement, dated as of October 3, 2025 (the “Investment Management Agreement”), with WhiteHawk Management , an affiliate of WhiteHawk Energy, LLC, of which Daniel Herz is a managing member. Fees incurred under the Investment Management Agreement were $15.8 million and $18.8 million for the three and six months ended June 30, 2026, respectively. Fees incurred under the Investment Management Agreement were $2.2 million and $3.6 million for the three and six months ended June 30, 2025, respectively. We expect a meaningful reduction in our operating expenses due to the elimination of management fees and other costs paid to ManagementCo.

Results of Operations

Three Months Ended June 30, 2026 Compared to the Three Months Ended June 30, 2025

Consolidated Results

The following tables summarize our consolidated revenue and expenses and production data for the three months ended June 30, 2026 and 2025:

(dollars in thousands, except for realized prices)

Revenue

Our consolidated revenues for the three months ended June 30, 2026, increased $8.0 million, as compared to the three months ended June 30, 2025. The increase in revenues was primarily due to an increase in natural gas, NGL and oil royalty revenue, an increase in gains from our commodity derivatives and an increase in lease bonus revenue. The increase in royalty revenues was primarily due to an increase in our production volumes of 57% from the acquisitions of additional mineral and royalty interests.

Natural gas revenues for the three months ended June 30, 2026, increased $2.5 million, or 24%, compared to the three months ended June 30, 2025. Natural gas production volumes increased 43% to 59,167 Mcf/day, resulting in a $3.9 million increase in natural gas sales primarily due to acquisitions of additional mineral and royalty interests. Realized natural gas prices decreased 13% to $2.42 per Mcf, resulting in a decrease in revenue of $0.6 million. The increase in revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.6 million.

NGLs revenues for the three months ended June 30, 2026, increased $2.2 million, or 211%, compared to the three months ended June 30, 2025. NGLs production volumes increased 151% to 1,213 Bbls/day, resulting in an approximately $1.9 million increase in NGLs sales. Realized NGLs prices increased 23% to $29.07 per Bbl, resulting in an increase in revenue of approximately $0.4 million. The increase in NGLs revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.3 million.

Oil revenues for the three months ended June 30, 2026, increased $4.7 million, compared to the three months ended June 30, 2025. Oil production volumes increased to 592 Bbls/day, resulting in a $4.6 million increase in oil sales. Realized oil prices increased 50% to $93.00 per Bbl, resulting in an increase in revenue of approximately $1.5 million. The increase in oil revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.7 million.

Commodity derivative gains totaled $11.0 million for the three months ended June 30, 2026, as compared to gains of $10.7 million for the three months ended June 30, 2025. The increase in commodity derivative gains of $0.3 million for the three months ended June 30, 2026, as compared to the three months ended June 30, 2025, was due to changes in commodity prices.

Lease bonus revenue increased $0.2 million for the three months ended June 30, 2026, as compared to the three months ended June 30, 2025. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing.

Operating expenses

General and administrative expenses for the three months ended June 30, 2026, decreased $5.2 million, or 54%, as compared to the three months ended June 30, 2025. The decrease was primarily attributable to a $6.2 million decrease in legal and professional expenses and a $0.4 million decrease in employee costs related to one-time transaction expenses, partially offset by a $0.9 million increase in stock based compensation, a $0.1 million increase in software expense, a $0.1 million increase in subscriptions expense, a $0.1 million in insurance expense, and a $0.1 million increase in travel-related expenses.

Management fees for the three months ended June 30, 2026, increased $13.7 million, or 629%, compared to the three months ended June 30, 2025. Management fees paid to WHIC Manager are calculated as a percentage of assets under management and a percentage of all distributions paid to the Company shareholders and each continue to increase as the Company continues to issue equity and make additional acquisitions. In addition, the Company paid a $13.5 million Liquidity Incentive Fee to WHIC Manager in connection with the IPO during the three months ended June 30, 2026.

Depletion, depreciation and accretion for the three months ended June 30, 2026, increased $4.2 million, or 71%, compared to the three months ended June 30, 2025. The increase was due to a 57% increase in quarter-over-quarter production volumes and a higher depletion rate, which increased to $1.60 per Mcfe for the three months ended June 30, 2026 from $1.47 per Mcfe for the three months ended June 30, 2025.

Other Income and Expenses

Interest expense relates to interest incurred on borrowings under our various credit facilities. The increase for the three months ended June 30, 2026, of $0.7 million, or 16%, compared to the three months ended June 30, 2025 was primarily due to a higher average amount outstanding under our Senior Notes.

Loss on extinguishment of debt for the three months ended June 30, 2026, increased $17.9 million, compared to the three months ended June 30, 2025. During the three months ended June 30, 2026, the Company amended the Senior Notes which was accounted for as an extinguishment and historical deferred financing costs were expensed. In addition, the Company incurred prepayment penalties as part of the repayments made on the Senior Notes during the quarter.

Change in fair value of earnout liability of $1.7 million for the three months ended June 30, 2026 relates to changes in fair value of the Earnout Amount.

Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025

Consolidated Results

The following tables summarize our consolidated revenue and expenses and production data for the six months ended June 30, 2026 and 2025:

(dollars in thousands, except for realized prices)

Revenue

Our consolidated revenues for the six months ended June 30, 2026, increased $29.6 million, as compared to the six months ended June 30, 2025. The increase in revenues was primarily due to an increase in natural gas, NGL and oil royalty revenue, an increase in gains from our commodity derivatives and an increase in lease bonus revenue. The increase in royalty revenues was primarily due to an increase in our production volumes of 85% from the acquisitions of additional mineral and royalty interests.

Natural gas revenues for the six months ended June 30, 2026, increased $18.5 million, or 98%, compared to the six months ended June 30, 2025. Natural gas production volumes increased 73% to 57,996 Mcf/day, resulting in a $15.7 million increase in natural gas sales primarily due to acquisitions of additional mineral and royalty interests. Realized natural gas prices increased 15% to $3.55 per Mcf, resulting in an increase in revenue of $2.0 million. The increase in revenue was partially offset by an increase in gathering, transportation and marketing expenses of $2.4 million.

NGLs revenues for the six months ended June 30, 2026, increased $3.0 million, or 160%, compared to the six months ended June 30, 2025. NGLs production volumes increased 145% to 1,000 Bbls/day, resulting in an approximately $2.9 million increase in NGLs sales. Realized NGLs prices increased 6% to $26.78 per Bbl, resulting in an increase in revenue of approximately $0.2 million. The increase in NGLs revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.4 million.

Oil revenues for the six months ended June 30, 2026, increased $7.3 million, compared to the six months ended June 30, 2025. Oil production volumes increased to 526 Bbls/day, resulting in a $7.2 million increase in oil sales. Realized oil prices increased 20% to $80.56 per Bbl, resulting in an increase in revenue of approximately $1.2 million. The increase in oil revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.9 million.

Commodity derivative gains totaled $5.7 million for the six months ended June 30, 2026, as compared to gains of $1.9 million for the six months ended June 30, 2025. The increase in commodity derivative gains of $3.8 million for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025, was due to changes in commodity prices.

Lease bonus revenue increased $0.7 million for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing.

Operating expenses

General and administrative expenses for the six months ended June 30, 2026, decreased $2.5 million, or 24%, as compared to the six months ended June 30, 2025. The decrease was primarily attributable to a $5.5 million decrease in legal and professional expenses related to one-time transaction expenses, partially offset by a $1.4 million increase in stock based compensation, a $0.5 million increase in employee and director expenses related to the growth of the Company, a $0.1 million increase in franchise taxes, a $0.2 million increase in software expense, a $0.2 million increase in subscriptions expense, a $0.2 million increase in insurance expenses, and a $0.2 million increase in travel-related expenses.

Management fees for the six months ended June 30, 2026, increased $15.2 million, or 423%, compared to the six months ended June 30, 2025. Management fees paid to WHIC Manager are calculated as a percentage of assets under management and a percentage of all distributions paid to the Company shareholders and each continue to increase as the Company continues to issue equity and make additional acquisitions. In addition, the Company paid a $13.5 million Liquidity Incentive Fee to WHIC Manager in connection with the IPO during the six months ended June 30, 2026.

Depletion, depreciation and accretion for the six months ended June 30, 2026, increased $10.7 million, or 116%, compared to the six months ended June 30, 2025. The increase was due to a 85% increase in year-over-year production volumes and a higher depletion rate, which increased to $1.63 per Mcfe for the six months ended June 30, 2026 from $1.40 per Mcfe for the six months ended June 30, 2025.

Other Income and Expenses

Interest expense relates to interest incurred on borrowings under our various credit facilities. The increase for the six months ended June 30, 2026, of $4.9 million, or 81%, compared to the six months ended June 30, 2025 was primarily due to a higher average amount outstanding under our Senior Notes.

Loss on extinguishment of debt for the six months ended June 30, 2026, increased $17.9 million, compared to the six months ended June 30, 2025. During the six months ended June 30, 2026, the Company amended the Senior Notes which was accounted for as an extinguishment and historical deferred financing costs were expensed. In addition, the Company incurred prepayment penalties as part of the repayments made on the Senior Notes during the quarter.

Change in fair value of earnout liability of $1.7 million for the six months ended June 30, 2026 relates to changes in fair value of the Earnout Amount.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been from capital raised from third-party investors, cash flows from operations and proceeds from the issuance of our Senior Notes. Following the completion of the IPO, we expect our primary sources of liquidity to be the proceeds retained from the IPO, cash flows from operations, proceeds drawn on our Revolving Credit Facility and proceeds from any future issuances of debt or equity securities. Future sources of liquidity may also include other credit facilities we may enter into in the future and/or additional issuances of debt or equity securities. Historically, our primary uses of cash have been for the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends, and we expect our primary uses of cash going forward to be for the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors. In addition, there can be no assurance that we will pay any dividends to holders of our Class A common stock or preferred stock, or as to the amount of any such dividends. For a discussion of these risks, please refer to the “Risk Factors” section of our Registration Statement on Form S-1/A.

We believe internally generated cash flows from operations and access to capital markets will provide us with sufficient liquidity and financial flexibility to meet our cash requirements, including normal operating needs, debt service obligations, our return of capital program, and capital expenditures, for at least the next 12 months and allow us to continue to execute our strategy of acquiring attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any drilling or completion capital expenditures, which are entirely borne by the E&P operators and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no subsequent capital expenditure requirements related to acquired properties. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash flow is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial and competitive, legislative, regulatory and other factors. We believe our cash flows from operations will be sufficient to fund our operating expenses, debt service obligations, and dividend payments for the next 12 months without accessing the capital markets. However, if we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us. There can be no assurance that capital markets financing will be available on favorable terms, or at all.

As of June 30, 2026 and December 31, 2025, our cash and cash equivalents was $13.2 million and $29.0 million, respectively.

Cash Flows for the Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025 (in thousands):

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators, as well as the timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the six months ended June 30, 2026 were $6.7 million as compared to cash flows used in operating activities of $4.0 million for the six months ended June 30, 2025. The increase was primarily a result of the increase in our production of 85% due to acquisitions and an increase of 28% in our realized prices.

Investing Activities

Cash flows used in investing activities totaled $39.7 million for the six months ended June 30, 2026, as compared to $307.8 million for the six months ended June 30, 2025, a decrease of $268.1 million due to the variance in our acquisitions of oil and gas properties, net of purchase price adjustments.

Financing activities

Cash flows provided by financing activities for the six months ended June 30, 2026 totaled $17.3 million as compared to cash flows provided by financing activities of $319.4 million for the six months ended June 30, 2025. During the six months ended June 30, 2026, cash flows provided by financing activities was primarily related to $270.7 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by dividends of $8.9 million paid to common and preferred stockholders during the six months ended June 30, 2026, common and preferred stock redemptions of $48.8 million, and $187.4 million repayments of the Senior Notes.

During the six months ended June 30, 2025, cash flows provided by financing activities was primarily related to $182.8 million of additional proceeds from our Senior Notes, net of repayments, and $169.3 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by preferred stock redemptions of $19.0 million and dividends of $7.8 million paid to common and preferred stockholders during the six months ended June 30, 2025.

Critical Accounting Policies and Related Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.

We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates and assumptions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Changes in estimates are accounted for prospectively.

Our estimates and classification of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of our natural gas and oil properties and/or the rate of depletion related to natural gas and oil properties.

Gas and Oil Properties

We use the successful efforts method of accounting for natural gas and oil producing properties, as further defined under Accounting Standards Codification 932, Extractive Activities—Oil and Natural Gas. Under this method, costs to acquire mineral interests in natural gas and oil properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of E&P operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved gas and oil properties. Capitalized costs for proved natural gas and oil mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved gas and oil properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions.

Impairment of Gas and Oil Properties

We evaluate our proved properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future net cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future net cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved gas and oil properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include, but are not limited to, commodity price outlooks, current and future operator activity, and analysis of recent mineral transactions in the surrounding area.

Crude Oil, Natural Gas and NGLs Reserve Quantities and Standardized Measure of Gas and Oil

Our estimates of natural gas, crude oil and NGLs reserves and associated future net cash flows are prepared or audited by our independent reservoir engineers. The SEC has defined proved reserves as the estimated quantities of gas and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves. Crude oil, natural gas and NGLs reserve engineering is a process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify positive or negative revisions of reserve estimates.

Revenue Recognition

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas, oil, and natural gas liquids sales from third-party operators may not be received for 30 to 120 days after the date production is delivered. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded based upon our royalty interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the operator. We have existing internal controls for our royalty income estimation process and related accruals, but actual third-party royalty income in future periods could differ materially from estimated amounts. Identified differences between our accrued revenue estimates and actual revenue received historically have not been significant.

Natural gas, NGLs and oil revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

We also earn revenue related to lease bonuses by leasing our mineral interests to E&P operators. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates and operator credit risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates and operator credit risk. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the crude oil, natural gas and NGLs production of our E&P operators, which affects the royalty payments we receive from our E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil, natural gas and NGL production has been volatile historically and we expect this volatility to continue in the future. The prices that our E&P operators receive for production depend on many factors outside of our or their control.

A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.5 million change in our natural gas revenues for the three months ended June 30, 2026. A $1.00 per Bbl change in NGLs and oil prices would have resulted in a $0.2 million change in our NGLs and oil revenues for the three months ended June 30, 2026. Royalties on natural gas sales, NGL sales and oil contributed 61%, 14% and 23%, respectively, of our total royalty revenues for the three months ended June 30, 2026.

A $0.10 per Mcf change in our realized natural gas price would have resulted in a $1.0 million change in our natural gas revenues for the six months ended June 30, 2026. A $1.00 per Bbl change in NGLs and oil prices would have resulted in a $0.3 million change in our NGLs and oil revenues for the six months ended June 30, 2026. Royalties on natural gas sales, NGL sales and oil contributed 74%, 9% and 15%, respectively, of our total royalty revenues for the six months ended June 30, 2026.

We may enter into derivative instruments from time to time, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows related to certain of our acquisitions. However, these instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. Refer to “Note 4—Commodity Derivative Financial Instruments” for further information.

Operator Credit Risk

Our principal exposures to credit risk are through receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators is acceptable.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under the Senior Notes which bears interest at a floating rate. The weighted average annual interest rate incurred on our borrowings under the Senior Notes during the six months ended June 30, 2026 was 10.3%. We estimate that an increase of 1.0% in the average interest rate during the six months ended June 30, 2026 would have resulted in an approximately $1.1 million increase in interest expense.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2026, as required by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2026 due to the material weaknesses in our internal control over financial reporting described below.

In connection with the preparation of our unaudited consolidated financial statements for the three months ended March 31, 2026, we identified material weaknesses in our internal control over financial reporting that we are currently working to remediate. These material weaknesses relate to: (a) controls over the quarterly close and account reconciliations process related to the reconciliation of related party balances were not designed at a sufficient level of precision to prevent or detect material misstatements in a timely manner; and (b) controls over business combinations did not contain a control specific to the recording of post combination adjustments related to the business combination effective date.

We have concluded that these material weaknesses in our internal control over financial reporting were primarily attributable to our business processes, personnel resources, and related internal controls not being sufficiently mature to support the complexity and timeline of financial reporting requirements.

Remediation Plan

We have begun to take, and intend to continue taking, steps to remediate the material weaknesses described above. Our remediation efforts include designing and implementing effective internal controls measures to improve our evaluation of disclosure controls and procedures and internal control over financial reporting. Specifically, we are instituting new and enhanced controls to improve and formalize the level of precision applied to the review of our financial statements, including the development and documentation of detailed review procedures. We are also introducing new documentation controls designed to ensure that sufficient supporting evidence exists to substantiate the amounts and balances included in our financial statements and to confirm that management review procedures were performed. However, these material weaknesses will not be considered remediated until the applicable controls have been in place for a sufficient period of time and have been tested and determined to be operating effectively.

We can give no assurance that additional material weaknesses will not be identified in the future. While we remain an emerging growth company, we are not required to provide an attestation report on internal control over financial reporting from our independent registered public accounting firm.

Changes in Internal Control Over Financial Reporting

Except for the remediation activities described above, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended June 30, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We are subject to certain risks and hazards due to the nature of our business activities. For a discussion of these risks, please refer to the “Risk Factors” section of our Registration Statement on Form S-1/A (File No. 333-295743), as filed with the Securities and Exchange Commission on June 5, 2026, which disclosure is incorporated herein by reference. There have been no material changes to the risk factors contained in the Form S-1/A. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.