COMSTOCK RESOURCES INC (CRK)

CIK: 0000023194. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-19.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=23194. Latest filing source: 0001193125-26-059001.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-19. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000023194.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000023194.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001193125-26-208551.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, 2025 (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 as well as with the Risk Factors contained in our Annual Report.

Results of Operations

Three Months Ended

March 31,

2026

2025

(In thousands, except per unit amounts)

Net Production Data:

Natural gas (MMcf)

97,855

115,029

Oil (MBbls)

11

10

Natural gas equivalent (MMcfe)

97,919

115,091

Revenues:

Natural gas sales

$

418,275

$

412,286

Oil sales

758

702

Total natural gas and oil sales

$

419,033

$

412,988

Expenses:

Production and ad valorem taxes

$

10,425

$

11,179

Gathering and transportation

$

41,804

$

42,617

Lease operating

$

28,281

$

35,000

Exploration

$

9,343

$

2,150

Average Sales Price:

Natural gas (per Mcf)

$

4.27

$

3.58

Oil (per Bbl)

$

68.91

$

70.20

Average equivalent (Mcfe)

$

4.28

$

3.59

Expenses ($ per Mcfe):

Production and ad valorem taxes

$

0.10

$

0.10

Gathering and transportation

$

0.43

$

0.37

Lease operating

$

0.29

$

0.30

Gas Services:

Gas services revenue

$

166,501

$

99,866

Gas services expense

$

162,856

$

116,769

Revenues –

Natural gas and oil sales of $419.0 million for the three months ended March 31, 2026 increased by $6.0 million (1%) as compared to $413.0 million for the first quarter of 2025. The increase was due to higher natural gas prices realized in the first quarter of 2026 as compared to the same period in 2025. The average realized price for our natural gas was $4.27 per thousand cubic feet ("Mcf"), which increased 19% from the average realized natural gas price in the first quarter of 2025. Our natural gas production for the first quarter of 2026 decreased 15% to 97.9 billion cubic feet ("Bcf") (1.1 Bcf per day). Natural gas production for the first quarter of 2025 was 115.0 Bcf (1.3 Bcf per day) and was sold at an average price of $3.58 per Mcf.

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COMSTOCK RESOURCES, INC.

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:

Three Months Ended March 31,

2026

2025

Average Realized Natural Gas Price:

Natural gas, per Mcf

$

4.27

$

3.58

Cash settlements on derivative financial instruments, per Mcf

(0.82

)

(0.06

)

Price per Mcf, including cash settlements on derivative financial instruments

$

3.45

$

3.52

Gas service revenues of $166.5 million increased $66.6 million (67%) for the first quarter of 2026 from $99.9 million in the first quarter of 2025. The increases were primarily due to higher natural gas prices related to sales of natural gas purchased to utilize our excess transport capacity.

We reported a gain on sale of assets of $1.8 million for the first quarter of 2026, which was primarily due to post-closing adjustments related to the divestiture of our Shelby Trough properties in East Texas during the fourth quarter of 2025.

Costs and Expenses –

Our production and ad valorem taxes decreased $0.8 million (7%) to $10.4 million for the first quarter of 2026 from $11.2 million in the first quarter of 2025. The decrease was primarily due to lower production in the first quarter of 2026.

Gathering and transportation costs for the first quarter of 2026 decreased $0.8 million (2%) to $41.8 million as compared to $42.6 million in the first quarter of 2025. The decrease was due primarily to lower production.

Our lease operating expense of $28.3 million ($0.29 per Mcfe) for the first quarter of 2026 decreased $6.7 million (19%) as compared to our lease operating expense of $35.0 million ($0.30 per Mcfe) for the first quarter of 2025. The decrease was due to lower production in the first three months of 2026.

Gas service expenses of $162.9 million increased $46.1 million (39%) for the first quarter of 2026 from $116.8 million in the first quarter of 2025. 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 $26.4 million to $141.5 million in the first quarter of 2026 from $167.9 million in the first quarter of 2025 due to lower natural gas production in the first quarter of 2026. Our DD&A per equivalent Mcf produced was $1.45 per Mcfe for the quarter ended March 31, 2026 which was comparable to $1.46 for the quarter ended March 31, 2025.

General and administrative expenses, which are reported net of overhead reimbursements, increased to $18.2 million for the first quarter of 2026 as compared to $11.1 million in the first quarter of 2025. The increase was primarily due to higher employee compensation, including stock-based compensation, which increased to $7.4 million in the first quarter of 2026 as compared to $4.4 million in the first quarter of 2025.

We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter ended March 31, 2026, we had net gains related to our derivative financial instruments of $2.4 million, as compared to net losses on derivative financial instruments of $330.3 million during the quarter ended March 31, 2025, resulting from the decline in future natural gas prices since December 31, 2025. Realized net losses from our price risk management program were $80.4 million for the quarter ended March 31, 2026 as compared to realized net losses of $8.0 million for the quarter ended March 31, 2025.

Interest expense was $53.1 million and $54.8 million for the quarters ended March 31, 2026 and 2025, respectively. The decrease in interest expense was due primarily to decreased borrowings on our bank credit facility.

Exploration expense was $9.3 million for the first quarter of 2026 as compared to $2.2 million for the first quarter of 2025, which was related to the acquisition of seismic data in our Western Haynesville area.

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COMSTOCK RESOURCES, INC.

Income taxes for the quarters ended March 31, 2026 and 2025 were a provision of $12.0 million and a benefit of $143.3 million, respectively. Income taxes for the quarters ended March 31, 2026 and 2025 reflect an effective tax rate of 9.6% and 55.4%, 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, release of valuation allowance on deferred tax assets, state income taxes, changes in certain nondeductible items and the income attributable to noncontrolling interest.

We reported net income of $112.5 million, or $0.38 per share for the quarter ended March 31, 2026. Income from operations for the first quarter of 2026 was $174.9 million as compared to income from operations of $126.2 million for the first quarter of 2025. We reported a net loss of $115.4 million or $0.40 per share for the quarter ended March 31, 2025.

Cash Flows, Liquidity and Capital Resources

Cash Flows

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

Three Months Ended

March 31,

2026

2025

(In thousands)

Sources of cash and cash equivalents:

Operating activities

$

271,965

$

174,746

Borrowings on bank credit facilities, net of repayments

137,000

95,000

Contributions from noncontrolling interest

—

59,500

Proceeds from asset sales

1,820

—

Total

$

410,785

$

329,246

Uses of cash and cash equivalents:

Capital expenditures

$

404,948

$

298,261

Distributions to noncontrolling interest

8,217

2,219

Income tax withholdings on equity awards

4,213

2,690

Debt and stock issuance costs

2,552

—

Total

$

419,930

$

303,170

Cash flows from operating activities. Net cash provided by our operating activities increased $97.2 million (56%) to $272.0 million in the first three months of 2026 from $174.7 million in the same period in 2025. The increase was due primarily to higher natural gas prices.

Contributions from noncontrolling interest. During the first three months of 2025, our noncontrolling interest partner contributed $59.5 million to our midstream partnership to fund the build-out of our Western Haynesville midstream system.

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COMSTOCK RESOURCES, INC.

Capital expenditures. Our capital expenditures are summarized in the following table:

Three Months Ended

March 31,

2026

2025

(In thousands)

Acquisitions:

Unproved property

$

19,040

$

9,684

Exploration and development:

Development leasehold costs

3,368

3,556

Exploratory drilling and completion costs

174,775

100,107

Development drilling and completion costs

158,559

145,578

Other development costs

6,570

515

Asset retirement obligations

38

18

Total exploration and development

362,350

259,458

Other property and equipment

54,752

48,754

Total capital expenditures

$

417,102

$

308,212

Change in accrued capital expenditures and other

(1,252

)

(10,202

)

Prepaid drilling costs

(10,864

)

269

Change in asset retirement obligations

(38

)

(18

)

Total cash capital expenditures

$

404,948

$

298,261

We drilled 17 (15.3 net) wells and completed 13 (11.7 net) Haynesville and Bossier shale operated wells during the first three months of 2026. We currently expect to spend an additional $1.1 billion to $1.2 billion in the remaining nine months of 2026 on drilling, completion, infrastructure and other activity.

Liquidity and Capital Resources

As of March 31, 2026, we had $1.27 billion of liquidity, comprised of $1.15 billion of unused borrowing capacity under our bank credit facilities and $14.8 million of cash and cash equivalents on hand. $103 million of unused borrowing capacity under our PGS bank credit facility is restricted to PGS midstream activities. Our short and long-term capital requirements consist primarily of funding our development, exploration and midstream 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 facilities. 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

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-19. Report date: 2025-12-31.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of natural gas and oil in the United States. Our assets are concentrated in the Haynesville and Bossier shale located in North Louisiana and East Texas, a premier natural gas basin with superior economics due to the geographic proximity to Gulf Coast natural gas markets. We own interests in 1,724 producing natural gas and oil wells (959.7 net to us) and we operate 1,074 of these wells.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven natural gas and oil properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire seismic data used for exploration, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our natural gas and oil at current market prices at the point where our wells connect to third party purchaser pipelines or terminals. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production to long-haul gas pipelines. We market our products in several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of and demand for natural gas. Natural gas prices have historically been volatile and are likely to remain volatile in the future.

Our operating costs are generally comprised of several components, including costs of our field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all natural gas and oil exploration and production companies, we face the challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, natural gas and oil, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our natural gas and oil wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $20.8 million as of December 31, 2025.

Prices for natural gas and oil have been highly volatile in recent years but we expect our natural gas production to increase in 2026, assuming we maintain a sufficient development program to offset expected production declines from our producing wells. The level of our drilling activity is dependent on natural gas prices. If we are unable to offset production declines with the new wells we plan to drill in 2026 and future periods, our production volumes and cash flows from our operating activities may not be sufficient to fund our capital expenditures, and thus, we may need to either curtail drilling activity or seek additional borrowings, which would result in an increase in our interest expense in 2026 and future periods.

We recognized $29.1 million of impairments to our non-operated Eagle Ford shale unproved and proved properties in 2025 to adjust the carrying value of our Eagle Ford shale assets to their estimated fair value. We may need to recognize further impairments of our natural gas and oil properties if natural gas and oil prices decline, and as a result, the expected future cash flows from these properties become insufficient to recover their carrying value.

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COMSTOCK RESOURCES, INC.

Results of Operations

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

Our operating data for the year ended December 31, 2025 and 2024 are summarized below:

Year Ended December 31,

2025

2024

(In thousands except per unit amounts)

Net Production Data:

Natural gas (MMcf)

450,202

527,548

Oil (MBbls)

37

50

Natural gas equivalent (MMcfe)

450,423

527,847

Revenues:

Natural gas sales

$

1,425,857

$

1,043,886

Oil sales

2,292

3,597

Total natural gas and oil sales

$

1,428,149

$

1,047,483

Expenses:

Production and ad valorem taxes

$

40,453

$

57,437

Gathering and transportation

$

166,108

$

194,890

Lease operating

$

122,662

$

130,504

Exploration

$

10,071

$

—

Average Sales Price:

Natural gas (per Mcf)

$

3.17

$

1.98

Oil (per Bbl)

$

61.95

$

71.94

Average equivalent (Mcfe)

$

3.17

$

1.98

Expenses ($ per Mcfe):

Production and ad valorem taxes

$

0.09

$

0.11

Gathering and transportation

$

0.37

$

0.37

Lease operating

$

0.27

$

0.25

Gas Services:

Gas services revenue

$

500,202

$

206,097

Gas services expense

$

516,224

$

205,407

Natural gas and oil sales. Natural gas and oil sales of $1.4 billion in 2025 increased by $0.4 billion, or 36%, as compared to $1.0 billion in 2024. The increase was primarily due to higher prices received for our natural gas production. Our 2025 natural gas production decreased 15% to 450.2 Bcf (1.2 Bcf per day), which was sold at an average price of $3.17 per Mcf as compared to 527.5 Bcf (1.4 Bcf per day) sold at an average price of $1.98 in 2024.

We utilize natural gas derivative financial instruments to manage our exposure to changes in prices of natural gas 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:

Year Ended December 31,

2025

2024

Average Realized Natural Gas Price:

Natural gas, per Mcf

$

3.17

$

1.98

Cash settlements on derivative financial instruments, per Mcf

0.04

0.39

Price per Mcf, including cash settlements on derivative

   financial instruments

$

3.21

$

2.37

Gas services revenues. Gas services revenues of $500.2 million in 2025 increased $294.1 million (143%) from $206.1 million in 2024. Gas services activities include sales of natural gas purchased from unaffiliated third parties for resale and fees received from unaffiliated third parties for natural gas gathering and treating services. Gas services revenues increased in 2025 due primarily to higher natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.

Gain on sale of assets. We reported a gain on sale of assets of $291.9 million in 2025, which was primarily related to the divestiture of our Shelby Trough properties in East Texas for net proceeds of $417.2 million. We also sold our interest in

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COMSTOCK RESOURCES, INC.

our Cotton Valley properties in East Texas and North Louisiana for net proceeds of $15.2 million. In 2024, we sold our interest in certain non-operated properties and realized a gain of $0.9 million.

Production and ad valorem taxes. Our production and ad valorem taxes decreased $17.0 million (30%) to $40.5 million in 2025 from $57.4 million in 2024. This decrease was primarily related to a decrease in Louisiana production tax and ad valorem tax rates and lower natural gas production volumes in 2025.

Gathering and transportation. Gathering and transportation costs decreased $28.8 million (15%) to $166.1 million in 2025 as compared to $194.9 million in 2024. This decrease was due primarily to lower production volumes in 2025.

Lease operating expenses. Our lease operating expense of $122.7 million ($0.27 per Mcfe) in 2025 was $7.8 million, or 6% lower than lease operating expenses in 2024 of $130.5 million ($0.25 per Mcfe). The decrease in lease operating expense was due to lower production volumes as compared to 2024.

Gas services expenses. Gas services expenses of $516.2 million in 2025 were $310.8 million (151%) higher than gas services expenses in 2024 of $205.4 million. The increase was due primarily to higher natural gas prices for purchases of third-party natural gas for resale.

Depreciation, depletion and amortization expense ("DD&A"). DD&A expense decreased $154.2 million (19%) to $641.2 million in 2025 from $795.4 million in 2024. Our DD&A expense per equivalent Mcf produced was $1.42 per Mcfe in 2025 as compared to $1.51 per Mcfe in 2024. The decrease in DD&A rate was primarily due to the increase in estimated proved undeveloped reserves used in determining the DD&A rate, which resulted from the higher natural gas price used in the estimation of proved reserves at December 31, 2025.

General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, increased to $48.7 million in 2025 from $39.4 million in 2024 due primarily to higher personnel costs including stock-based compensation. Stock-based compensation included in general and administrative expenses was $21.2 million and $15.3 million in 2025 and 2024, respectively.

Impairment of oil and gas properties. We recorded an impairment to our Eagle Ford shale proved and unproved natural gas and oil properties of $29.1 million in 2025. This charge primarily resulted from diminished activity on our leasehold acreage in the area by operators, low oil prices and our capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

Derivative financial instruments. We use derivative financial instruments as part of our price risk management program to protect the cash flow we generate from our operating activities. We had net gains on derivative financial instruments of $82.5 million for 2025 as compared to $10.2 million for 2024. Realized net gains from our natural gas price risk management program were $20.1 million in 2025 as compared to $207.8 million in 2024. We recognized unrealized gains on derivative financial instruments of $62.4 million and unrealized losses of $197.6 million in 2025 and 2024, respectively.

Interest expense. Interest expense was $222.8 million for 2025 as compared to $210.6 million for 2024. Included in interest expense was amortization of the premiums or discounts on our senior notes and the debt issuance cost amortization associated with our outstanding debt. The non-cash interest expense for 2025 totaled $12.0 million compared with $11.5 million for 2024. The increase in interest expense in 2025 was due primarily to the issuance of our 6.75% senior notes in 2024 and increased borrowings on our bank credit facility in 2025.

Exploration expense. Exploration expense was $10.1 million in 2025, which was related to the acquisition of seismic data for our Western Haynesville area.

Income taxes. Our income tax provision was $88.5 million in 2025 as compared to a benefit of $149.1 million in 2024. Our effective tax rate of 17% in 2025 differed from the federal income tax rate of 21% due primarily to research and development and other tax credits claimed in 2025 and state income taxes. Our effective tax rate of 41% in 2024 differed from the federal income tax rate of 21% primarily due to changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes.

Net income. We reported net income of $420.2 million or $1.43 per diluted share in 2025 and a net loss of $218.8 million or $0.76 per diluted share in 2024. The net income in 2025 is primarily due to the impact of higher natural gas prices in 2025, gain on sale of assets of $291.9 million and the unrealized gain on our derivative financial instruments of $62.4 million. Income from operations in 2025 was $645.9 million as compared to loss from operations of $168.6 million in 2024.

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COMSTOCK RESOURCES, INC.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Discussions of 2024 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report on Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2024 filed with the SEC on February 21, 2025.

Cash Flows, Liquidity and Capital Resources

Cash Flows

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

Year Ended December 31,

2025

2024

(in thousands)

Sources of cash and cash equivalents:

Operating activities

$

899,607

$

620,337

Proceeds from asset sales

428,868

1,214

Contributions from noncontrolling interest

215,500

60,500

Issuance of 6.75% senior notes

—

372,000

Issuance of common stock

—

100,450

Total

$

1,543,975

$

1,154,501

Uses of cash and cash equivalents:

Capital expenditures

$

1,344,278

$

1,085,490

Repayments on bank credit facility, net of borrowings

155,000

65,000

Distributions to noncontrolling interest

16,520

3,653

Income tax withholdings on equity awards

11,010

3,373

Debt and stock issuance costs

36

6,855

Total

$

1,526,844

$

1,164,371

Cash flows from operating activities. Net cash provided by our operating activities increased $279.3 million (45%) to $899.6 million in 2025 from $620.3 million in 2024. The increase was primarily due to the higher natural gas prices we realized in 2025.

Proceeds from asset sales. In 2025, we sold our Shelby Trough properties in East Texas and our Cotton Valley properties in East Texas and North Louisiana and other assets. In 2024, we sold certain non-operated properties for net proceeds of $1.2 million.

Contributions from and distributions to noncontrolling interest. In 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system. During 2025 and 2024, our noncontrolling partner contributed $215.5 million and $60.5 million, respectively, to the midstream partnership. Also during 2025 and 2024, we distributed preferred dividends of $16.5 million and $3.7 million, respectively, to our noncontrolling partner.

Issuance of 6.75% senior notes and debt issuance costs. 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 outstanding borrowings on our bank credit facility. We incurred $6.8 million of debt issuance costs associated with the senior note issuance.

Issuance of common stock and stock issuance costs. In 2024, we issued 12,500,000 shares of common stock to two entities controlled by our majority stockholder in a private placement, receiving total proceeds of $100.5 million.

Capital expenditures. The increase in capital expenditures of $258.8 million is primarily due to higher drilling and completion activities in 2025.

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COMSTOCK RESOURCES, INC.

Our capital expenditures are summarized in the following table:

Year Ended December 31,

2025

2024

(in thousands)

Acquisitions:

Unproved property

$

54,670

$

106,386

Exploration and development:

Developmental leasehold costs

14,562

13,461

Exploratory drilling and completion costs

490,429

354,557

Development drilling and completion costs

517,375

503,550

Other development costs

32,493

30,500

Asset retirement obligations

444

1,594

Total exploration and development

1,109,973

1,010,048

Midstream

223,592

85,377

Other property

17,893

2,264

Total capital expenditures

$

1,351,458

$

1,097,689

Change in accrued capital expenditures and other

(1,656

)

1,383

Prepaid drilling costs

(5,002

)

(11,988

)

Asset retirement obligations

(522

)

(1,594

)

Total cash capital expenditures

$

1,344,278

$

1,085,490

We currently expect to spend approximately $1.4 billion to $1.5 billion in 2026 on our development and exploration projects primarily focused on the continued development of our Haynesville/Bossier shale properties including the exploration and development of our Western Haynesville acreage. We also expect to spend $100 million to $150 million in our Western Haynesville midstream partnership. Under our 2026 operating plan, we currently expect to drill 66 operated horizontal wells (59.7 net) and to turn 72 operated wells (63.1 net) to sales in 2026.

Liquidity and Capital Resources

As of December 31, 2025, we had $260.0 million outstanding under a bank credit facility. Aggregate commitments under the 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 our assets and those of our restricted 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% on the unused portion of the committed borrowing base. The bank credit facility places certain restrictions upon our and our restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem our 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 December 31, 2025.

As of December 31, 2025, we had $1.3 billion of liquidity, comprised of $1.2 billion of unused borrowing capacity under our bank credit facility and $23.9 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 or borrowings under our bank credit facility. The timing of most of our capital expenditures is mostly discretionary. We have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. If our plans or assumptions change or prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing. We expect to fund future acquisitions, depending on the size and timing, with future operating cash flow, borrowings under our bank credit facility, or other debt or equity financings, to the extent available. The availability and attractiveness of debt or equity 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. 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.

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COMSTOCK RESOURCES, INC.

Our contractual obligations consist primarily of principal and interest payments on our senior notes and bank credit facility, natural gas transportation and gathering contracts and other operating lease obligations. Interest payments under our senior notes and bank credit facility are $182.6 million for 2026, $180.6 million for 2027, $166.3 million for 2028, $75.0 million for 2029 and $2.4 million for 2030. Our natural gas transportation and gathering contracts extend to 2031 and 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 commitments thereafter.

Federal and State Taxation

On December 31, 2025, we had $1.4 billion in U.S. federal net operating loss carryforwards, $1.8 billion in certain state net operating loss carryforwards, $17.7 million of U.S. federal research and development tax credits and $11.0 million of certain state research and development tax credits. As a result of a change of control in August 2018, our ability to use U.S. federal net operating losses ("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 carry-forward 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, 2021 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, 2022. Currently, we are under examination with the United States Internal Revenue Service and the state of Louisiana and we believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions will be sustained under audit or the final resolution will not have a material effect on our 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 have benefited from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation, which are included in our income tax provision for the year ending December 31, 2025.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for natural gas and oil producing activities. The full cost method allows the capitalization of all costs associated with finding natural gas and oil reserves. The successful efforts method allows only for the capitalization of costs associated with developing proven natural gas and oil properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities.

Natural gas and oil reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved natural gas and oil reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities and timing of natural gas and oil that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future natural gas and oil prices may all differ materially from those assumed in these estimates. Proved reserve estimates included in this report were prepared by the Company's engineers and audited by independent petroleum engineers.

The information regarding present value of the future net cash flows attributable to our proved natural gas and oil reserves are estimates only and should not be construed as the current market value of the estimated natural gas and oil reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

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COMSTOCK RESOURCES, INC.

Impairment of natural gas and oil properties. We evaluate our proved properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property's proved and risk adjusted probable natural gas and oil reserves estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. 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 the average first day of the month historical price for the year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of our natural gas and oil leases. During 2025, we recognized impairment charges of $29.1 million to reduce the capitalized costs of our proved and unproved natural gas and oil properties in the Eagle Ford shale to their fair value. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to our 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 further impairments in the carrying values of our proved and unproved natural gas and oil properties in the future.

Income Taxes. We account 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 future tax consequences attributable to the future utilization of existing tax NOLs and other types of 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.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our 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. We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized. As a result, we established valuation allowances for our deferred tax assets and U.S. federal and state NOL carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. We will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future reporting periods.

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COMSTOCK RESOURCES, INC.