COMSTOCK RESOURCES INC

(1)

Summary of Significant Accounting Policies

Accounting policies used by Comstock Resources, Inc. and subsidiaries reflect natural gas and oil industry practices and conform to accounting principles generally accepted in the United States of America.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Comstock Resources, Inc., its wholly owned or controlled subsidiaries and a variable interest entity for which Comstock is the primary beneficiary (collectively, "Comstock" or the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in natural gas and oil properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements. Net income (loss) and comprehensive income (loss) are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Certain amounts in prior period footnote disclosures have been reclassified to conform with current period presentation.

Comstock entered into an agreement with an affiliate of Quantum Capital Solutions ("Quantum"), in 2023 to form Pinnacle Gas Services, LLC ("PGS"), a midstream company in Comstock's Western Haynesville area. As part of the transaction, Comstock contributed a high-pressure pipeline and a natural gas treating plant. Quantum committed to contribute up to $300 million to fund future expansion costs. Quantum is entitled to a 12% dividend on its invested capital and 80% of any distributions from Pinnacle until an investment return hurdle is met. After the return hurdle is met, Quantum's ownership reduces to 30%. Comstock operates and manages PGS pursuant to a management services agreement. The Board of PGS is comprised of five members: three selected by Comstock and two selected by Quantum. PGS is considered a variable interest entity to Comstock.

Comstock has the power to direct the activities that most significantly impact the performance of PGS and has the obligation to absorb losses or right to receive benefits that could potentially be significant to PGS. Accordingly, Comstock is considered the primary beneficiary and consolidates the assets, liabilities and results of operations of PGS in the accompanying consolidated financial statements. PGS assets that cannot be used by Comstock include $363.9 million of other property and equipment as of December 31, 2025. Other PGS assets that cannot be used by Comstock and PGS liabilities for which creditors do not have recourse to Comstock's assets are not material to the Company's consolidated financial statements. The portion of PGS net income and stockholders' equity not attributable to Comstock's controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of operations and statements of stockholders' equity.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated natural gas and oil reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.

Concentration of Credit Risk, Accounts Receivable and Credit Losses

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company's accounts receivable are due from either purchasers of natural gas and oil or participants in natural gas and oil wells for which the Company serves as the operator. Generally, operators of natural gas and oil wells have the right to offset future revenues against unpaid charges related to operated wells. Natural gas and oil sales are generally unsecured. The Company's policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been recorded for the years ended December 31, 2025, 2024 and 2023, respectively.

Other Current Assets

Other current assets at December 31, 2025 and 2024 consist of the following:

Fair Value Measurements

The Company holds or has held certain financial assets and liabilities that are required to be measured at fair value in the financial statements. These include cash and cash equivalents held in bank accounts and derivative financial instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:

Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.

Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.

The following presents the carrying amounts and the fair values of the Company's financial instruments as of December 31, 2025 and 2024:

(1)

The Company's commodity-based derivatives are classified as Level 2 and measured at fair value using a market approach using third party pricing services and other active markets or broker quotes that are readily available in the public markets.

(2)

The carrying value of our floating rate debt outstanding approximates fair value.

(3)

The fair value of the Company's fixed rate debt was based on quoted prices as of December 31, 2025 and 2024, respectively, a Level 1 measurement.

Property and Equipment

The Company follows the successful efforts method of accounting for its natural gas and oil properties. Costs incurred to acquire natural gas and oil leasehold are capitalized. Acquisition costs for proved natural gas and oil properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related natural gas and oil reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas.

Exploratory well costs are initially capitalized as proved property in the consolidated balance sheets but charged to exploration expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. The changes in capitalized exploratory well costs are as follows:

As of December 31, 2025 and 2024, the Company had no exploratory wells for which costs have been capitalized greater than one year.

The estimated future costs of dismantlement, restoration, plugging and abandonment of natural gas and oil properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. Exploration expense includes geological and geophysical expenses and delay rentals related to exploratory natural gas and oil properties, costs of unsuccessful exploratory drilling and impairments of unproved properties. As of December 31, 2025 and 2024, the unproved properties primarily relate to future drilling locations that were not included in proved undeveloped reserves. Most of these future drilling locations are located on acreage where the reservoir is known to be productive but have been excluded from proved reserves due to uncertainty on whether the wells would be drilled within the next five years as required by SEC rules in order to be included in proved reserves. The costs of unproved properties are transferred to proved natural gas and oil properties when they are either drilled or they are reflected in proved undeveloped reserves and amortized on an equivalent unit-of-production basis. Costs associated with unevaluated exploratory acreage are periodically assessed for impairment on a property by property basis, and any impairment in value is included in exploration expense. Exploratory drilling costs are initially capitalized as proved property but charged to expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company assesses the need for an impairment of the costs capitalized for its proved natural gas and oil properties when events or changes in circumstances, such as a significant drop in commodity prices, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its natural gas and oil properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for natural gas and oil prices, future natural gas and oil production, production costs, capital expenditures, and the total proved and risk-adjusted probable natural gas and oil reserves expected to be recovered. Management's natural gas and oil price outlook is developed based on multiple third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of the natural gas and oil leases. In the fourth quarter of 2025, the Company measured the fair value of its Eagle Ford shale proved property using Level 3 unobservable inputs at $1.2 million and as a result, the Company recognized an impairment charge of $7.8 million. Comstock also recognized an impairment charge to its Eagle Ford shale unproved property of $21.3 million. This charge primarily resulted from diminished activity in the area on its leasehold acreage by operators, low oil prices and the Company's capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

The Company's estimates of undiscounted future net cash flows attributable to its natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be future impairments in the carrying values of our natural gas and oil properties.

Other property and equipment consists primarily of pipelines and natural gas treating plants ("midstream assets"), computer equipment, furniture and fixtures, office buildings and an airplane which are depreciated over estimated useful lives ranging from three to 50 years on a straight-line basis. The following table presents the balances of other property and equipment and accumulated depreciation as of December 31, 2025 and 2024:

The Company also assesses the need for an impairment of its midstream assets when events or changes in circumstances, such as a significant decline in natural gas volumes gathered and processed, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the pipelines and natural gas treating plants, then impairment is recognized to the extent the capitalized costs of the pipelines and natural gas treating plants exceed their estimated fair value. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for future natural gas gathering and processing volumes, operation costs and capital expenditures and the expected future net cash flows are discounted at an appropriate rate to determine fair value.

Goodwill

The Company had goodwill of$335.9 million as of December 31, 2025 and 2024. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets in a business combination.

The Company is required to conduct an annual review of goodwill for impairment and performs the assessment of goodwill on October 1st of each year. If the carrying value of goodwill exceeds the fair value, an impairment charge would be recorded for the difference between fair value and carrying value. The Company performed its assessment of goodwill as of October 1, 2025 and determined there was no indication of impairment.

Leases

The Company had right-of-use lease assets of$94.7 million and$73.8 million as of December 31, 2025 and 2024, respectively, related to its corporate office lease, certain office equipment, vehicles and drilling rigs with corresponding short-term and long-term liabilities. The value of the lease assets and liabilities are determined based upon discounted future minimum cash flows contained within each of the respective contracts, including the effects of early termination provisions. The Company determines if contracts contain a lease at inception of the contract. Since most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate at the commencement date of the lease. To the extent that contract terms representing a lease are identified, leases are identified as being either an operating lease or a finance-type lease. Comstock currently has no finance-type leases. Right-of-use lease assets represent the Company's right to use an underlying asset for the lease term and the related lease liabilities represent its obligation to make lease payments under the terms of the contracts. Short-term leases that have an initial term of one year or less are not capitalized; however, amounts paid for those leases are included as part of its lease cost disclosures. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Comstock contracts for a variety of equipment used in its natural gas and oil exploration and development operations. Contract terms for this equipment vary broadly, including the contract duration, pricing, scope of services included along with the equipment, cancellation terms, and rights of substitution, among others. The Company's drilling and completion operations routinely change due to changes in commodity prices, demand for natural gas and oil, and the overall operating and economic environment. Accordingly, Comstock manages the terms of its contracts for drilling rigs and completion equipment so as to allow for maximum flexibility in responding to these changing conditions. The Company's hydraulic fracturing fleet contracts are on terms of less than one year and include rights of substitution. As of December 31, 2025, the Company hadfour drilling rig lease contracts with athree-year term with options to extend the term by mutual agreement at mutually acceptable terms or terminate the contracts at any time without default by the lessor. The Company's other drilling rig contracts are presently either for periods of one year or less, or they are on terms that provide for cancellation with 30 or 45 days advance notice without a specified expiration date. The costs associated with drilling and completion operations are accounted for under the successful efforts method, which generally require that these costs be capitalized as part of our proved natural gas and oil properties on our balance sheet unless they are incurred on exploration wells that are unsuccessful, in which case they are charged to exploration expense. For drilling rig leases, the Company has elected the practical expedient to not separate lease components from non-lease components in the determination of their lease asset and liability values.

Lease costs recognized during the years ended December 31, 2025, 2024 and 2023 were as follows:

Cash payments for operating leases associated with right-of-use assets included in cash provided by operating activities were$4.0 million,$3.9 million and$3.8 million for the years ended December 31, 2025, 2024 and 2023, respectively. Cash payments for operating leases associated with right-of-use assets included in cash used for investing activities were$87.7 million,$63.5 million and$174.3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025 and 2024, the operating leases had a weighted average remaining term of 2.4 years and 2.0 years, respectively, and the weighted-average discount rate used to determine the present value of future operating lease payments was 6.8% and 7.3%, respectively.

As of December 31, 2025, expected future payments related to contracts that contain operating leases were as follows:

Accrued Expenses

Accrued expenses at December 31, 2025 and 2024 consist of the following:

Reserve for Future Abandonment Costs

The Company's asset retirement obligations relate to future plugging and abandonment costs of its natural gas and oil properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.

The following table summarizes the changes in the Company's total estimated liability:

Stock-based Compensation

The Company has stock-based employee compensation plans under which stock awards, comprised primarily of restricted stock and performance share units ("PSUs"), are issued to employees and non-employee directors. The Company follows the fair value-based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Forfeitures are recognized as they occur.

Segment Reporting

The Company presently operates inone business segment, the exploration and production of North American natural gas and oil, primarily in the Haynesville and Bossier shale. This is consistent with the internal reporting provided to the Company's Chief Executive Officer, who is the chief operating decision maker ("CODM"). The CODM evaluates the performance of the Company and allocates resources based on consolidated financial information.

The measure of segment profit or loss used by the CODM is consolidated net income, which is provided in the accompanying consolidated statements of operations. The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.

Derivative Financial Instruments and Hedging Activities

The Company accounts for derivative financial instruments (including derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings and in net cash flows from operating activities. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities.

Major Purchasers

In 2025, the Company had three major purchasers of its natural gas production that accounted for 18%,11% and 10% of its total natural gas and oil sales. In 2024, the Company hadtwo major purchasers of its natural gas production that accounted for 21% and 12% of its total natural gas and oil sales. In 2023, the Company hadthree major purchasers of its natural gas production that accounted for 20%,17% and 10% of its total natural gas and oil sales. The loss of any of these purchasers would not have a material adverse effect on the Company as there is an available market for its natural gas and oil production from other purchasers.

Revenue Recognition and Gas Balancing

Comstock produces natural gas and oil and reports revenues separately for each of thesetwo primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Costs incurred to gather or transport each product prior to the transfer of control are recognized as operating expenses.

Gas services revenues represent sales of natural gas purchased for resale from unaffiliated third parties and fees received for gathering and treating services provided by PGS to third parties. Revenues are recognized upon completion of the gathering and treating of contracted natural gas volumes and delivery of purchased natural gas volumes to the Company's customers. Profits and losses earned in the gathering and treating of natural gas produced by the Company's natural gas wells are eliminated in consolidation. Revenues and expenses associated with natural gas purchased for resale are presented on a gross basis in the Company's consolidated statements of operations as the Company acts as the principal in the transaction by assuming the risks and rewards from ownership of the natural gas volumes purchased and the responsibility to deliver the natural gas volumes to their sales point.

All natural gas and oil and gas services revenues are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party for oil and vary for natural gas based upon the terms set out in the confirmations between both parties. Prices for sales of natural gas and oil are generally based upon terms that are common in the natural gas and oil industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for natural gas and oil routinely fluctuate based on changes in these factors. Prices for gathering and treating services are generally fixed in nature but can vary due to the quality of the gas being treated. Each unit of production (thousand cubic feet of natural gas and barrel of crude oil ) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.

Comstock has elected to exclude all taxes from the measurement of transaction prices, and its natural gas and oil revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling natural gas and oil, on behalf of royalty owners and working interest owners. Natural gas and oil sales revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. Gas services revenue is recorded in the month the services are performed and purchased gas is sold based on an estimate of natural gas volumes and contract prices. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenues received have not been significant. The amount of natural gas or oil sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2025 or 2024.

The Company has recognized accounts receivable of$203.5 million and$145.4 million as of December 31, 2025 and 2024, respectively, from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the natural gas and oil properties operated by the Company of$30.5 million,$30.7 million and$29.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Income Taxes

The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the tax consequences attributable to the future utilization of existing net operating loss and other carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

Earnings Per Share

Unvested restricted stock containing non-forfeitable rights to dividends are included in common stock outstanding and are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. At December 31, 2025 and 2024,1,957,381 and 2,091,087 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a non-forfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's shareholders.

Weighted average shares of unvested restricted stock outstanding were as follows:

PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up totwo times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the performance period. The treasury stock method is used to measure the dilutive effect of PSUs.

None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses. For the year ended December 31, 2023, the weighted average shares of unvested restricted stock and PSUs were excluded from the computation of earnings per share because to include them would have been antidilutive to the calculation.

Basic and diluted income (loss) per share were determined as follows:

Supplementary Information with Respect to the Consolidated Statements of Cash Flows

For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Cash payments made for interest and income taxes and other non-cash investing and financing activities were as follows:

(1)

State tax payments were made in Texas and Louisiana.

Recent Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09 "Improvements to Income Tax Disclosures". ASU 2023-09 requires additional disclosures around effective tax rates and cash income taxes paid and is effective for public entities for annual periods beginning after December 15, 2024. ASU 2023-09 wasimplemented retrospectively in this 2025 Annual Report. See (9) Income Taxes for the impact on the Company's disclosures.

In November 2024, the FASB issued ASU 2024-03 "Disaggregation of Income Statement Expenses". ASU 2024-03 requires additional disclosure, in the notes to the financial statements, of specified information about certain costs and expenses, including purchases of inventory, employee compensation, depreciation, intangible asset amortization and depreciation, depletion and amortization recognized as part of oil and gas-producing activities included in each relevant expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027 and will not have an impact on the Company's reported results of operations, financial position or liquidity but will have an impact on the Company's financial statement disclosures. The Company is still evaluating the impact of this standard on its financial statement disclosures.

(2)

Acquisitions and Dispositions of Natural Gas and Oil Properties

Acquisitions

During 2025, 2024 and 2023, the Company spent$54.7 million,$106.4 million and$98.6 million on its leasing program to acquire 17,856,265,290 and 79,741 net acres, respectively, of undeveloped acreage in the Western Haynesville area through direct leasing or through acquisitions of undeveloped rights from third-party operators.

Dispositions

On December 2, 2025, the Company sold its interest in its Shelby Trough assets in East Texas for net proceeds of $417.2 million. The assets sold included 163 (74.8 net) producing wells and 36,000 net leasehold acres in Nacogdoches, San Augustine and Sabine counties in Texas. The Company realized a $292.3 million pre-tax gain on the sale of the unproved property. The producing wells and associated proved undeveloped reserves were valued at $120.5 million and recorded as a retirement of the Company's proved property. The Company's reserve for future abandonment costs was reduced by $1.7 million as a result of the divestiture.

On September 2, 2025, the Company sold its interest in its Cotton Valley assets in East Texas and North Louisiana for net proceeds of $15.2 million. The assets sold included the Company's interest in 883 (770.9 net) producing wells and 46 (27.3 net) inactive wells. The Company incurred a $1.5 million pre-tax loss on the divestiture and the Company's reserve for future abandonment costs was reduced by $13.8 million.

The Company sold its interests in certain non-operated natural gas and oil properties for$1.2 million and$41.3 million in 2024 and 2023, respectively.

(3)

Natural Gas and Oil Producing Activities

Set forth below is certain information regarding the aggregate capitalized costs of natural gas and oil properties and costs incurred by the Company for its natural gas and oil property acquisition, development and exploration activities:

Capitalized Costs

Costs Incurred

(4)

Long-term Debt

Long-term debt is comprised of the following:

The discount and premium on the 6.75% senior notes due 2029 are being amortized over its life using the effective interest rate method. Debt issuance costs are amortized over the lives of the bank credit facility and senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.

The following table summarizes Comstock's principal amount of debt as of December 31, 2025 by year of maturity:

As of December 31, 2025, the Company had$260.0 million outstanding under a bank credit facility. Aggregate commitments under the bank credit facility are$1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base, which is currently set at$2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of the assets of the Company and its restricted subsidiaries and bear interest at the Company's option, at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the unused portion of the committed borrowing base. The Company also pays a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. The weighted average interest rate on borrowings under the bank credit facility were 6.76% and 7.32% during the years ended December 31, 2025 and 2024, respectively. The bank credit facility places certain restrictions upon the Company's and its restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. The Company was in compliance with the covenants as of December 31, 2025.

In April 2024, the Company issued $400.0 million principal amount of 6.75% senior notes due 2029 (the "New 2029 Notes") in a private placement and received net proceeds after offering costs and deducting the initial purchasers' discounts of $365.2 million, which were used to pay down the outstanding borrowings on the Company's bank credit facility. The New 2029 Notes have substantially identical terms as the Company's $1,223.9 million aggregate principal amount of 6.75% senior notes due 2029, which mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year.

(5)

Commitments and Contingencies

The Company has drilling rig contracts with terms ranging from less than one year tothree years. The service contracts with terms less than one year are generally for terms ranging from 30 to 45 days. The Company has four drilling rigs under contract with initial terms ofthree years that were put into service in 2023, 2024 and 2025. These four rigs qualify as operating leases and their corresponding lease obligation is reflected on the Company's balance sheet as of December 31, 2025. In 2025, the Company took delivery of one additional drilling rig with aone-year term, which has a remaining commitment of $3.2 million.

The Company has natural gas transportation and gathering contracts which extend to 2035. Commitments under these contracts are$85.4 million for 2026,$84.2 million for 2027,$79.3 million for 2028,$67.6 million for 2029,$27.7 million for 2030 and$58.9 million for 2031 through 2035. During the years ended December 31, 2025, 2024 and 2023, expenditures under these contracts totaled$86.3 million,$92.8 million and$96.5 million, respectively.

From time to time, the Company is involved in certain litigation that arise in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material adverse effect on the Company's financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at December 31, 2025 or 2024.

(6)

Stockholders' Equity

The authorized capital of the Company is 405,000,000 shares, of which 400,000,000 shares are common stock, $0.50 par value per share, and 5,000,000 are preferred stock, $10.00 par value per share.

In March 2024, the Company issued 12,500,000 shares of common stock in a private placement to two entities controlled by Comstock's majority stockholder, receiving proceeds of $100.5 million. Following the issuance, Comstock's majority stockholder's beneficial ownership in the Company increased to 67%. As a result of open market purchases made by the Company's majority stockholder during the third quarter of 2024, beneficial ownership increased to 71%.

(7)

Stock-based Compensation

The Company grants restricted shares of common stock and PSUs to key employees and directors as part of their compensation. Grants are made pursuant to the Company's 2019 Long-term Incentive Plan (the "2019 Plan"), which was approved by the Company's shareholders on May 31, 2019. Future authorized equity awards available under the 2019 Plan as of December 31, 2025 were 9,451,616 shares of common stock.

Stock-based compensation expense is included in general and administrative expenses. During the years ended December 31, 2025, 2024 and 2023 the Company had$21.2 million,$15.3 million and$9.9 million, respectively, in stock-based compensation expense.

Restricted Stock

The fair value of restricted stock grants is amortized over the vesting period, generallyone year tothree years, using the straight-line method. The fair value of each restricted share on the date of grant is equal to the market price of a share of the Company's stock.

A summary of restricted stock activity is presented below:

Performance Share Units

The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria are met during a performance period. The performance periods consist ofthree years. The performance criteria for the PSUs are based on the Company's annualized total stockholder return ("TSR") for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.

The fair value of PSUs was measured at the grant date using the Geometric Brownian Motion Model. Significant assumptions used in this simulation include the Company's expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company's peers. Assumptions regarding volatility included the historical volatility of each company's stock and the implied volatilities of publicly traded stock options.

Significant assumptions used to value PSUs included:

A summary of PSU activity is presented below:

The fair value of PSUs is amortized over the vesting period ofthree years, using the straight-line method. The final number of shares of common stock issued may vary depending upon the performance multiplier and can result in the issuance ofzero to 3,207,832 shares of common stock based on the achieved performance ranges from zero totwo hundred percent.

(8)

Retirement Plan

The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match the employees' contributions to the plan. Matching contributions to the plan were approximately$2.2 million,$2.1 million and$1.9 million for the years ended December 31, 2025, 2024 and 2023, respectively.

(9)

Income Taxes

Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates.

The following is an analysis of the consolidated income tax provision (benefit):

In recording deferred income tax assets, the Company considers whether it is more likely than not that its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. The Company will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future periods.

The tax effects of significant temporary differences representing the net deferred tax liabilities were as follows:

The difference between the customary rate of 21.0% and the effective tax rate on income (losses) is due to the following:

(1)

State taxes in Texas and Louisiana contributed to the tax effect of this category.

At December 31, 2025, Comstock had the following carryforwards available to reduce future income taxes:

The Company's ability to use net operating losses ("NOLs") generated before its ownership change in 2018 to reduce taxable income is limited under IRC Section 382. NOLs that exceed the Section 382 limitation in any year continue to be allowed as carry forwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. U.S. federal NOLs incurred prior to 2018 generally have a 20-year life until they expire. NOLs generated in 2018 and after would be carried forward indefinitely. NOLs arising after the date of an ownership change are not affected by the 382 limitation. If the Company does not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then it will lose the ability to apply those NOLs as offsets to future taxable income. The Company estimates that all of the U.S. federal NOL carryforwards expiring in 2037 and$1.2 billion of the estimated state NOL carryforwards will expire unused.

The Company's federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination, with the Company's 2022 and 2023 federal income tax returns currently under examination with the United States Internal Revenue Service. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. The Company is also currently under examination with the state of Louisiana. In both the federal and state examinations, the Company believes that its significant filing positions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

In July 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into United States federal law. The Company is benefiting from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation and has included these benefits in its income tax provision for the year ended December 31, 2025.

(10)

Derivative Financial Instruments and Hedging Activities

Comstock generally uses commodity price swaps, basis swaps and collars to hedge natural gas prices to manage price risk. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.

All of the Company's derivative financial instruments are used for risk management purposes and, by policy, none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative financial instruments involve payment or receipt of premiums. The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity contract. None of the Company's derivative contracts are designated as fair value or cash flow hedges. The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses) in the consolidated statements of operations and as separate components within cash flows from operating activities in the consolidated statements of cash flows. All of Comstock's natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index.

The Company had the following outstanding natural gas price derivative financial instruments at December 31, 2025:

Subsequent to December 31, 2025, the Company entered into natural gas collar contracts to hedge an additional 58.4 Bcf of 2027 natural gas production at an average ceiling price of $4.37 per MMBtu and an average floor price of $3.50 per MMBtu.

The aggregate fair value of the Company's derivative financial instruments is presented on a gross basis in the accompanying consolidated balance sheets. The classification of derivative financial instruments between assets and liabilities consists of the following:

The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses). Gains and losses related to cash settlements and changes in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of operations were as follows:

(11)

Related Party Transactions

The Company operates natural gas and oil properties held by partnerships owned by its majority stockholder. Comstock charges the partnership for the costs incurred to drill, complete and produce the wells, as well as drilling and operating overhead fees. Comstock also provides natural gas marketing services to the partnerships in return for a fee equal to $0.02 per Mcf for natural gas marketed. The Company received$1.1 million,$1.1 million and$1.3 million in 2025, 2024 and 2023, respectively, for operating and marketing services provided to the partnership. The fees received for the services are reflected as a reduction of general and administrative expenses in the accompanying consolidated statements of operations.

In connection with the operation of the wells, the Company had a$3.6 million and$5.5 million receivable from the partnerships at December 31, 2025 and 2024, respectively.

(12)

Subsequent Event

In January 2026, PGS entered into an agreement with Quantum under which PGS agreed to redeem all of the outstanding Class B Units of PGS in exchange for cash consideration of $440 million plus any accrued but unpaid distributions. The redemption is expected to be completed in the first half of 2026.

(13)

Natural Gas and Oil Reserves Information (Unaudited)

Set forth below is a summary of the Company's proved natural gas and oil reserves:

Revisions of previous estimates. Revisions of previous estimates in 2024 and 2023 were primarily attributable to the significantly lower natural gas and oil prices that were used to determine proved reserves at the end of each year, which resulted in many of the Company's proved undeveloped locations being excluded from reserves since they did not generate an adequate return at those lower prices.

Extensions and discoveries. Extensions and discoveries for 2025, 2024 and 2023 were primarily comprised of proved reserve additions attributable to the wells drilled in the current year that were not classified as proved undeveloped in prior years and additional proved undeveloped locations that are planned to be drilled in the Company's current development plan that were not included in the prior year's reserve estimates. 2025 extensions and discoveries include proved undeveloped reserves that were excluded in 2024 and 2023 due to low natural gas prices.

Sales of minerals in place. During 2025, the Company sold certain natural gas and oil properties for$432.4 million. During 2024, the Company sold its interest in certain non-operated wells for$1.2 million.

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves:

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves:

The standardized measure of discounted future net cash flows was determined based on the simple average of the first of month market prices for natural gas and oil for each year. Prices used in determining quantities of natural gas and oil reserves and future cash inflows from natural gas and oil reserves represent prices received at the Company's sales point. These prices have been adjusted from posted or index prices for both location and quality differences. Prices used in determining natural gas and oil reserves quantities and cash flows are as follows:

Proved reserve information utilized in the preparation of the financial statements were based on estimates prepared by the Company's petroleum engineering staff in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company's reserves are located onshore in the continental United States of America. The Company retained an independent petroleum consultant to conduct an audit of the Company's 2025 reserve estimates. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates. The engineering firm was selected for their geographic expertise and their historical experience.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.