Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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:

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 incur any drilling-related capital expenditures and incur 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

In August 2026, the Company, through certain of its subsidiaries, signed a definitive purchase and sale agreement with Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC (collectively, "SJM II") to acquire natural gas mineral and royalty interests in the Appalachian and Haynesville Basins for an aggregate purchase price of $105.0 million, subject to customary adjustments. The transaction closed on September 25, 2026, for aggregate consideration paid at closing of approximately $96.8 million, after giving effect to customary adjustments.

On September 21, 2026, the Company completed a private placement of 2,873,563 shares of Class A Common Stock at a purchase price of $26.10 per share, generating aggregate gross proceeds of approximately $75.0 million, before deducting placement agent fees and other expenses. In September 2026, the Company also issued and sold 50,000 shares of Series E Preferred Stock at a price of $1,000.00 per share, generating aggregate gross proceeds of $50.0 million. Proceeds from these offerings, together with cash on hand, were used to fund the SJM II acquisition described above.

On September 25, 2026, in connection with the closing of the acquisition, OpCo entered into an amendment to the Revolving Credit Facility that increased both the aggregate elected commitments and the borrowing base from $150.0 million to $175.0 million. As of September 30, 2026, no amounts were drawn under the Revolving Credit Facility, and $175.0 million was available for future borrowings.

Subsequent to September 30, 2026, on October 6, 2026, the Company commenced a continuous, best efforts registered public offering of up to 100,000 shares of Series F Redeemable Preferred Stock at a public offering price of up to $1,000.00 per share. In connection with the offering, the Company entered into a dealer manager agreement with Preferred Capital Securities, LLC. The registration statement on Form S-1 for the offering was declared effective by the SEC on October 6, 2026. The Series F Redeemable Preferred Stock provides for cumulative dividends at a fixed annual rate of 7.5% of its $1,000.00 per share stated value. The dealer manager is not required to sell any specific number or dollar amount of shares.

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, 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 periods presented include the results of operations of the Three Rivers Acquisition, PHX Merger and SJM II Acquisition only from their respective acquisition dates. 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, PHX Merger, and SJM II Acquisition, see Note 3-Acquisitions. 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 general and administrative 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 WHIC Management Agreement with WhiteHawk Management, an affiliate of WhiteHawk Energy, LLC, of which Daniel Herz is a managing member. Fees incurred under the WHIC Management Agreement were $0.0 million and $18.8 million for the three and nine months ended September 30, 2026, respectively. Fees incurred under the WHIC Management Agreement were $2.7 million and $6.3 million for the three and nine months ended September 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 September 30, 2026 Compared to the Three Months Ended September 30, 2025

Consolidated Results

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

Revenue

Our consolidated revenues for the three months ended September 30, 2026, decreased $2.8 million, as compared to the three months ended September 30, 2025. The decrease in revenues was primarily due to a decrease in gains from our commodity derivatives, partially offset by an increase in natural gas, NGL and oil royalty revenue and an increase in lease bonus revenue. The increase in royalty revenues was primarily due to an increase in our production volumes of 10% from the acquisitions of additional mineral and royalty interests as well as a 7% increase in realized prices.

Natural gas revenues for the three months ended September 30, 2026, increased $0.9 million, or 7%, compared to the three months ended September 30, 2025. Natural gas production volumes increased 6% to 61,254 Mcf/day, resulting in a $0.8 million increase in natural gas sales primarily due to acquisitions of additional mineral and royalty interests. Realized natural gas prices remained stable at $2.53 per Mcf during the three months ended September 30, 2026, compared to $2.52 during the three months ended September 30, 2025.

NGLs revenues for the three months ended September 30, 2026, increased $0.7 million, or 47%, compared to the three months ended September 30, 2025. NGLs production volumes increased 49% to 1,149 Bbls/day, resulting in an approximately $0.7 million increase in NGLs sales. Realized NGLs prices decreased 1% to $20.15 per Bbl, resulting in a decrease in revenue of less than $0.1 million. The increase in NGLs revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.1 million.

Oil revenues for the three months ended September 30, 2026, increased $1.4 million, or 53%, compared to the three months ended September 30, 2025. Oil production volumes increased 17% to 518 Bbls/day, reflecting increased production. Realized oil prices increased 31% to $83.61 per Bbl, contributing to the increase in oil sales. The increase in oil revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.2 million.

Commodity derivative gains totaled $3.2 million for the three months ended September 30, 2026, as compared to gains of $9.3 million for the three months ended September 30, 2025. The decrease in commodity derivative gains of $6.1 million for the three months ended September 30, 2026, as compared to the three months ended September 30, 2025, was due to changes in commodity prices.

Lease bonus revenue increased $0.7 million for the three months ended September 30, 2026, as compared to the three months ended September 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 re-leasing.

Operating expenses

General and administrative expenses for the three months ended September 30, 2026, increased $1.8 million, or 62%, as compared to the three months ended September 30, 2025. The increase was primarily attributable to a $1.1 million increase in stock-based compensation, a $0.6 million increase in legal and professional expenses, a $0.2 million increase in insurance expense, a $0.1 million increase in software expense and a $0.1 million increase in travel-related expenses, partially offset by a $0.4 million decrease in employee costs related to one-time transaction expenses.

Management fees for the three months ended September 30, 2026, decreased $2.7 million, or 100%, compared to the three months ended September 30, 2025. The decrease was attributable to the elimination of management fees and other costs paid to ManagementCo in conjunction with the Internalization. Management fees paid to WHIC Manager were calculated as a percentage of assets under management and a percentage of all distributions paid to the Company's shareholders and historically increased as the Company continued to issue equity and make additional acquisitions.

Depletion, depreciation and accretion for the three months ended September 30, 2026, increased $1.8 million, or 20%, compared to the three months ended September 30, 2025. The increase was due to a 10% increase in year-over-year production volumes and a higher depletion rate, which increased to $1.62 per Mcfe for the three months ended September 30, 2026 from $1.48 per Mcfe for the three months ended September 30, 2025.

Other Income and Expenses

Interest expense relates to interest incurred on borrowings under our various credit facilities. The decrease for the three months ended September 30, 2026, of $4.4 million, or 67%, compared to the three months ended September 30, 2025 was primarily due to a lower average amount outstanding under our Senior Notes.

Change in fair value of earnout liability of $2.7 million for the three months ended September 30, 2026 relates to changes in fair value of the Earnout Amount.

Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025

Consolidated Results

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

Revenue

Our consolidated revenues for the nine months ended September 30, 2026, increased $26.9 million, as compared to the nine months ended September 30, 2025. The increase in revenues was primarily due to an increase in natural gas, NGL and oil royalty revenue and an increase in lease bonus revenue, partially offset by a decrease in gains from our commodity derivatives. The increase in royalty revenues was primarily due to an increase in our production volumes of 49% from the acquisitions of additional mineral and royalty interests as well as a 23% increase in realized prices.

Natural gas revenues for the nine months ended September 30, 2026, increased $19.6 million, or 61%, compared to the nine months ended September 30, 2025. Natural gas production volumes increased 42% to 59,094 Mcf/day, resulting in a $15.2 million increase in natural gas sales primarily due to acquisitions of additional mineral and royalty interests. Realized natural gas prices increased 14% to $3.20 per Mcf, resulting in an increase in revenue of $1.9 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 nine months ended September 30, 2026, increased $3.7 million, or 111%, compared to the nine months ended September 30, 2025. NGLs production volumes increased 98% to 1,050 Bbls/day, resulting in an approximately $3.5 million increase in NGLs sales. Realized NGLs prices increased 7% to $24.34 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 $0.5 million.

Oil revenues for the nine months ended September 30, 2026, increased $8.7 million, or 294%, compared to the nine months ended September 30, 2025. Oil production volumes increased 207% to 523 Bbls/day, resulting in a $7.9 million increase in oil sales. Realized oil prices increased 28% to $81.58 per Bbl, resulting in an increase in revenue of approximately $1.7 million. The increase in oil revenue was partially offset by an increase in gathering, transportation and marketing expenses of $1.2 million.

Commodity derivative gains totaled $8.9 million for the nine months ended September 30, 2026, as compared to gains of $11.2 million for the nine months ended September 30, 2025. The decrease in commodity derivative gains of $2.3 million for the nine months ended September 30, 2026, as compared to the nine months ended September 30, 2025, was due to changes in commodity prices.

Lease bonus revenue increased $1.5 million for the nine months ended September 30, 2026, as compared to the nine months ended September 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 re-leasing.

Operating expenses

General and administrative expenses for the nine months ended September 30, 2026, decreased $0.8 million, or 6%, as compared to the nine months ended September 30, 2025. The decrease was primarily attributable to a $4.9 million decrease in legal and professional expenses related to one-time transaction expenses, partially offset by a $2.5 million increase in stock based compensation, a $0.3 million increase in software expense, a $0.2 million increase in subscriptions expense, a $0.4 million increase in insurance expenses, a $0.3 million increase in travel-related expenses, a $0.1 million increase in franchise taxes, a $0.1 million increase in investor relations expense and a $0.1 million increase in rent expense.

Management fees for the nine months ended September 30, 2026, increased $12.5 million, or 197%, compared to the nine months ended September 30, 2025. Management fees paid to WHIC Manager were calculated as a percentage of assets under management and a percentage of all distributions paid to the Company's shareholders and historically increased as the Company continued 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 nine months ended September 30, 2026.

Depletion, depreciation and accretion for the nine months ended September 30, 2026, increased $12.5 million, or 69%, compared to the nine months ended September 30, 2025. The increase was due to a 49% increase in year-over-year production volumes and a higher depletion rate, which increased to $1.63 per Mcfe for the nine months ended September 30, 2026 from $1.44 per Mcfe for the nine months ended September 30, 2025.

Other Income and Expenses

Interest expense relates to interest incurred on borrowings under our various credit facilities. The increase for the nine months ended September 30, 2026, of $0.5 million, or 4%, compared to the nine months ended September 30, 2025 was primarily due to a higher average amount outstanding under our Senior Notes.

Loss on extinguishment of debt for the nine months ended September 30, 2026, increased $17.9 million, compared to the nine months ended September 30, 2025. During the nine months ended September 30, 2026, the Company amended the Senior Notes, with the amendment accounted for as an extinguishment and historical deferred financing costs expensed. In addition, the Company incurred prepayment penalties as part of the repayments made on the Senior Notes as a part of the IPO.

Change in fair value of earnout liability of $1.0 million for the nine months ended September 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 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 September 30, 2026 and December 31, 2025, our cash and cash equivalents were $23.7 million and $29.0 million, respectively.

Cash Flows for the Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 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 nine months ended September 30, 2026 were $17.1 million as compared to $8.6 million for the nine months ended September 30, 2025. The increase was primarily a result of the increase in our production of 49% due to acquisitions and an increase of 23% in our realized prices.

Investing Activities

Cash flows used in investing activities totaled $149.4 million for the nine months ended September 30, 2026, as compared to $309.6 million for the nine months ended September 30, 2025, a decrease of $160.2 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 nine months ended September 30, 2026 totaled $127.0 million as compared to cash flows provided by financing activities of $324.5 million for the nine months ended September 30, 2025. During the nine months ended September 30, 2026, cash flows provided by financing activities were primarily related to $392.4 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by dividends of $13.3 million paid to common and preferred

stockholders during the nine months ended September 30, 2026, common and preferred stock redemptions of $49.3 million, and $193.7 million of repayments of the Senior Notes.

During the nine months ended September 30, 2025, cash flows provided by financing activities were primarily related to $179.0 million of additional proceeds from our Senior Notes, net of repayments, and $222.8 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by common and preferred stock redemptions of $58.5 million and dividends of $13.1 million paid to common and preferred stockholders during the nine months ended September 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, at the least annually, 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 90 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.