Comstock Resources Inc: Form 10-Q for the period ended Sep 30, 2025

This report contains forward-looking statements that involve risks, uncertainties and assumptions that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 including those described under the heading "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2024 (the "Annual Report"). All statements other than statements of historic facts contained, or incorporated by reference, in this report, may be forward-looking statements. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors. Such forward-looking statements are based on management's current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described herein. Although the we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. You are cautioned not to place undue reliance on the forward-looking statements included in this report, which speak only as of the date made. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard thereto or any change of events, conditions or circumstances on which any such statement was based, except as required by law. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our Annual Report.

Results of Operations

(In thousands, except per unit amounts)

Revenues –

Natural gas and oil sales of $308.6 million for the three months ended September 30, 2025 increased by $55.0 million (22%) as compared to $253.6 million for the third quarter of 2024. The increase was due to higher natural gas prices realized in the third quarter of 2025 as compared to the same period in 2024. The average realized price for our natural gas was $2.75 per thousand cubic feet ("Mcf"), which increased 45% from the average realized natural gas price in the third quarter of 2024. Our natural gas production for the third quarter of 2025 decreased 16% to 111.8 billion cubic feet ("Bcf") (1.2 Bcf per day). Natural gas production for the third quarter of 2024 was 133.1 Bcf (1.4 Bcf per day) and was sold at an average price of $1.90 per Mcf.

Natural gas and oil sales of $1.06 billion for the nine months ended September 30, 2025 increased by $302.4 million (40%) as compared to $759.2 million for the nine months ended September 30, 2024, which was also primarily due to higher natural gas prices, which increased by 67% during the first nine months of 2025 as compared with 2024 prices. Our natural gas production for the first nine months of 2025 decreased 16% to 339.0 Bcf (1.2 Bcf per day), and was sold at an average price of $3.13 per Mcf as compared to 403.4 Bcf (1.5 Bcf per day) sold at an average price of $1.87 in the first nine months of 2024.

We utilize natural gas price derivative financial instruments to manage our exposure to changes in prices of natural gas and to protect returns on investment from our drilling activities. The following table presents our natural gas prices before and after the effect of cash settlements of our derivative financial instruments:

Gas service revenues of $141.3 million increased $90.4 million (178%) for the third quarter of 2025 from $50.8 million in the third quarter of 2024. Gas service revenues of $371.4 million increased $243.5 million (190%) for the first nine months of 2025 from $127.9 million for the first nine months of 2024. The increases were primarily due to higher natural gas prices related to sales of natural gas purchased to utilize our excess transport capacity.

Costs and Expenses –

Our production and ad valorem taxes decreased $1.4 million (11%) to $11.2 million for the third quarter of 2025 from $12.6 million in the third quarter of 2024. The decrease was primarily due to lower production in the third quarter of 2025. Production and ad valorem taxes decreased $16.8 million (34%) to $33.0 million for the first nine months of 2025 from $49.7 million in the first nine months of 2024. The decrease was also attributable to the decrease in production in 2025 and a decrease in Louisiana production tax and ad valorem tax rates.

Gathering and transportation costs for the third quarter of 2025 decreased $14.0 million (26%) to $40.0 million as compared to $54.0 million in the third quarter of 2024. Gathering and transportation costs for the first nine months of 2025 decreased $26.1 million (17%) to $124.3 million as compared to $150.5 million for the first nine months of 2024. The decrease was due primarily to lower production.

Our lease operating expense of $28.8 million ($0.26 per Mcfe) for the third quarter of 2025 was comparable to our lease operating expense of $29.2 million ($0.22 per Mcfe) for the third quarter of 2024. Lease operating expense of $94.9 million ($0.28 per Mcfe) for the first nine months of 2025 decreased $4.2 million (4%) from lease operating expense of $99.1 million ($0.25 per Mcfe) for the first nine months of 2024. The lease operating expense rate increased due to the fixed nature of much of our lease operating costs and lower production in the first nine months of 2025.

Gas service expenses of $141.7 million increased $89.1 million (169%) for the third quarter of 2025 from $52.6 million in the third quarter of 2024. Gas service expenses of $385.2 million increased $252.4 million (190%) for the first nine months of 2025 from $132.8 million for the first nine months of 2024. The increase was primarily due to higher natural gas prices related to purchases of third party natural gas for resale.

Depreciation, depletion and amortization ("DD&A") decreased $51.0 million to $157.4 million in the third quarter of 2025 from $208.4 million in the third quarter of 2024 due to lower natural gas production in the third quarter of 2025. Our DD&A per equivalent Mcf produced was $1.41 per Mcfe for the quarter ended September 30, 2025 as compared to $1.56 for the quarter ended September 30, 2024. DD&A decreased $109.6 million to $483.7 million for the first nine months of 2025 from $593.3 million during the first nine months of 2024. Our DD&A per equivalent Mcf produced was $1.43 per Mcfe for the nine months ended September 30, 2025 as compared to $1.47 for the nine months ended September 30, 2024. The decrease was primarily due to lower natural gas production and higher estimated proved undeveloped reserves used in determining the DD&A rate, which are the result of higher natural gas prices used in the estimation of proved reserves at September 30, 2025.

General and administrative expenses, which are reported net of overhead reimbursements, increased to $11.5 million for the third quarter of 2025 as compared to $9.9 million in the third quarter of 2024. General and administrative expenses increased to $34.9 million for the first nine months of 2025 as compared to $29.3 million during the first nine months of 2024. The increases in both periods were primarily due to higher employee compensation, including stock-based compensation, which increased to $5.6 million in the third quarter of 2025 as compared to $3.9 million in the third quarter of 2024. For the nine months ended September 30, 2025, stock-based compensation increased to $15.6 million as compared to the same period in 2024 of $11.4 million.

We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter ended September 30, 2025, we had net gains related to our derivative financial instruments of $142.8 million, as compared to net gains on derivative financial instruments of $75.2 million during the quarter ended September 30, 2024, resulting from the decline in future natural gas prices since June 30, 2025. Realized net gains from our price risk management program were $26.4 million for the quarter ended September 30, 2025 as compared to realized net gains of $51.4 million for the quarter ended September 30, 2024. Net gains on derivative financial instruments were $48.3 million for the first nine months of 2025 as compared to net gains of $89.2 million for the first nine months of 2024, resulting from an increase in future natural gas prices since December 31, 2024. Realized net gains from our price risk management program were $22.7 million for the first nine months of 2025 as compared to realized net gains of $160.0 million for the first nine months of 2024.

Interest expense was $56.7 million and $54.5 million for the quarters ended September 30, 2025 and 2024, respectively, and $166.7 million and $156.0 million for the nine months ended September 30, 2025 and 2024, respectively. The increase in interest expense was due primarily to increased borrowings on our bank credit facility.

Exploration expense was $6.6 million and $8.8 million for the three and nine months ended September 30, 2025, which was related to the acquisition of seismic data in our Western Haynesville area.

Income taxes for the quarters ended September 30, 2025 and 2024 were a provision of $18.6 million and a benefit of $14.7 million, respectively. Income taxes for the nine months ended September 30, 2025 and 2024 were a provision of $16.8 million and a benefit of $69.1 million, respectively. Income taxes for the quarters ended September 30, 2025 and 2024 reflect an effective tax rate of 13.6% and 36.4%, respectively. Income taxes for the nine months ended September 30, 2025 and 2024 reflect an effective tax rate of 11.2% and 29.7%, respectively. The difference between the federal statutory tax rate of 21% and our effective rate is primarily attributable to research and development and other tax credits, state income taxes, changes in certain nondeductible items and the income attributable to noncontrolling interest.

On September 2, 2025, we divested of certain properties in East Texas and North Louisiana for net proceeds of $15.2 million and recognized a $2.5 million pre-tax loss on the divestiture for the three and nine months ended September 30, 2025. During the three and nine months ended September 30, 2024, we sold our interest in certain non-operated properties and realized a gain of $910 thousand.

As a result of gains related to our derivative financial instruments, we reported net income of $118.1 million, or $0.40 per diluted share for the quarter ended September 30, 2025. Income from operations for the third quarter of 2025 was $50.2 million as compared to a loss from operations of $61.3 million for the third quarter of 2024. We reported a net loss of $25.7 million or $0.09 per share for the quarter ended September 30, 2024. In the first nine months of 2025, we reported net income of $133.4 million or $0.45 per diluted share. Income from operations for the first nine months of 2025 was $265.8 million. We reported a net loss of $163.4 million or $0.57 per share for the nine months ended September 30, 2024.

Cash Flows, Liquidity and Capital Resources

Cash Flows

The following table summarizes sources and uses of cash and cash equivalents:

(In thousands)

Cash flows from operating activities. Net cash provided by our operating activities increased $322.1 million (91%) to $675.4 million in the first nine months of 2025 from $353.3 million in the same period in 2024. The increase was due primarily to higher natural gas prices.

Contributions from noncontrolling interest. During the first nine months of 2025 and 2024, our noncontrolling interest partner contributed $156.5 million and $36.0 million, respectively, to our midstream partnership to fund the build-out of our Western Haynesville midstream system.

Proceeds from asset sales. In the first nine months of 2025, we sold certain properties for net proceeds of $15.2 million. In the first nine months of 2024, we sold our interest in certain non-operated properties for net proceeds of $1.2 million.

Issuance of 6.75% Senior Notes. In April 2024, we issued $400.0 million principal amount of 6.75% senior notes due 2029 in a private placement and received net proceeds after deducting the initial purchasers' discounts of $365.2 million, which were used to pay down the outstanding borrowings on our bank credit facility.

Issuance of common stock. In the first nine months of 2024, we issued 12,500,000 shares of common stock to two entities controlled by our majority stockholder in a private placement, receiving proceeds of $100.5 million.

Capital expenditures. Our 2024 capital expenditures included the acquisition of 189,000 net acres in our Western Haynesville area from an unaffiliated third party for $50.0 million. Our capital expenditures are summarized in the following table:

(In thousands)

We drilled 36 (31.8 net) wells and completed 36 (30.9 net) Haynesville and Bossier shale operated wells during the first nine months of 2025. We currently expect to spend an additional $250 million to $350 million in the remaining three months of 2025 on drilling, completion, infrastructure and other activity.

Liquidity and Capital Resources

As of September 30, 2025, we had $939.2 million of liquidity, comprised of $920 million of unused borrowing capacity under our bank credit facility and $19.2 million of cash and cash equivalents on hand. Our short and long-term capital requirements consist primarily of funding our development and exploration activities, acquisitions, payments of contractual obligations and debt service.

We expect to fund our future development and exploration activities with future operating cash flow and borrowings under our bank credit facility. The timing of most of our future capital expenditures is discretionary because of our limited number of material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We believe that our cash provided by operations and borrowings available under our bank credit facility will be sufficient to satisfy our foreseeable liquidity needs and capital expenditure requirements for at least the next twelve months. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

We do not have a specific acquisition budget for the remainder of 2025 because the timing and size of acquisitions are unpredictable. We intend to use our cash flows from operations, borrowings under our bank credit facility, or other debt or equity financing to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, natural gas and oil prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.

As of September 30, 2025, we had $580.0 million outstanding under our bank credit facility. Aggregate commitments under our bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under our bank credit facility are subject to a borrowing base that 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 our bank credit facility are secured by substantially all of our assets and those of our subsidiaries and bear interest at our 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 utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. Our bank credit facility places certain restrictions upon our and our 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. We were in compliance with the covenants as of September 30, 2025.

On October 10, 2025, we entered into an agreement with an unaffiliated third party to sell certain producing wells and undeveloped leasehold acreage in East Texas for $430 million in cash, subject to adjustment and customary closing conditions. The sale is expected to close in the fourth quarter of 2025 and has an effective date of October 1, 2025. We intend to use the net proceeds from the divestiture to reduce long-term debt.

Federal and State Taxation

At September 30, 2025, we had $743.0 million in U.S. federal net operating loss ("NOL") carryforwards and $1.8 billion in certain state NOL carryforwards. As a result of the change of control in August 2018, our ability to use NOLs to reduce taxable income is limited. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carryforward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $740.6 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.

Our federal income tax returns for the years subsequent to December 31, 2020 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2021. Currently, we are under examination with the United States Internal Revenue Service and the state of Louisiana and believe that our significant filing positions and deductions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, we have 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. We expect to benefit from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation and have included these expected benefits in our income tax provision for the three and nine months ended September 30, 2025.

Natural Gas and Oil Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of natural gas and oil. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, some of which are beyond our control. Factors influencing natural gas and oil prices include the level of global demand for oil, the foreign supply of natural gas and oil, the effect of the war in Ukraine and the geopolitical response to Russia's invasion, the establishment of and compliance with production quotas by oil exporting countries, weather conditions that determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future natural gas and oil prices with any degree of certainty. Sustained weakness in natural gas and oil prices may adversely affect our financial condition and results of operations and may also reduce the amount of natural gas and oil reserves that we can produce economically. Any reduction in our natural gas and oil reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in natural gas and oil prices can have a favorable impact on our financial condition, results of operations and capital resources.

As of September 30, 2025, we had natural gas price swaps to hedge approximately 50.1 Bcf of our 2025 natural gas production at an average price of $3.48 per MMBtu and approximately 116.8 Bcf of our 2026 production at an average price of $3.51 per MMBtu. We also had natural gas collars to hedge approximately 13.8 Bcf of our 2025 natural gas production at an average ceiling price of $3.80 and an average floor price of $3.50 and 167.9 Bcf of our 2026 production at an average ceiling price of $4.35 and an average floor price of $3.50. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

An increase of 10% in the market price of natural gas on September 30, 2025 would decrease the fair value of our natural gas price swaps and collars by approximately $91.7 million. A decrease of 10% in the market price of natural gas on September 30, 2025 would increase the fair value of our natural gas price swaps and collars by approximately $91.5 million. The impact of hypothetical changes in market prices of natural gas on our natural gas derivative financial instruments does not include the offsetting impact that the same hypothetical changes in market prices of natural gas may have on our physical sales of natural gas. Since our outstanding natural gas derivative financial instruments hedge only a portion of our forecasted physical gas production, a positive or negative impact to the fair value of our natural gas derivative financial instruments would be partially offset by our physical sales of natural gas.

Interest Rates

At September 30, 2025, we had approximately $3.2 billion principal amount of long-term debt outstanding. $965.0 million of our long-term debt bear interest at a fixed rate of 5.875% and $1.62 billion of our long-term debt bear interest at a fixed rate of 6.75%. As of September 30, 2025, the fair market value of the 5.875% senior notes due in 2030 and the 6.75% senior notes due in 2029 was $921.6 million and $1.61 billion, respectively, based on the market price of approximately 96% and 99%, respectively, of the face amount of such debt. At September 30, 2025, we had $580.0 million outstanding under our bank credit facility, which is subject to variable rates of interest that are tied to SOFR or the corporate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow.

As of September 30, 2025, we carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2025 to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and to provide reasonable assurance that information required to be disclosed by us is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. There were no changes in our internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that occurred during the three months ended September 30, 2025 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see "Item 1A. Risk Factors" in the Annual Report. There have been no material changes to the Risk Factors we have disclosed in the Annual Report.