COMSTOCK RESOURCES INC
For the period ended Dec 31, 2025. Filed Feb 19, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 19, 2026
CRK$13.41+0.7%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-21.
0000950170-25-024783
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-19.
0001193125-26-059001
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 58 previous paragraphs and 60 current paragraphs.
28 unchanged; 27 reworded; 5 added; 3 removed; 0 previous and 0 current paragraphs rearranged.
Tables are not compared: 4 previous and 4 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (5)
Current report
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.
Current report
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 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.
Current report
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.
Current report
Exploration expense. Exploration expense was $10.1 million in 2025, which was related to the acquisition of seismic data for our Western Haynesville area.
Current report
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.
Removed paragraphs (3)
Previous report
Common stock dividends. In 2023, we paid a quarterly cash dividend of 12.5¢ per share of common stock. We did not pay a dividend in 2024.
Previous report
Goodwill. We have goodwill of $335.9 million as of December 31, 2024 that was recorded in 2018. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets. We are not required to amortize goodwill as a charge to earnings; however, we are required to conduct an annual review of goodwill for impairment. We determine the potential for impairment of our goodwill by initially preparing a qualitative fair value assessment of our business value. In performing this qualitative assessment, we examine relevant events and circumstances that could have a negative effect on our business, including macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events.
Previous report
If the qualitative assessment indicates that it is more likely than not that our business is impaired, a quantitative analysis would be performed to assess our fair value and to determine the amount of impairment, if any, that requires recognition. When performing a quantitative impairment assessment of goodwill, fair value is determined based on a market approach or an income approach. If the carrying value of goodwill exceeds the fair value calculated using the quantitative approach, an impairment charge would be recorded for the difference between fair value and carrying value. If oil or natural gas prices decrease, drilling efforts are unsuccessful or our market capitalization declines, it is reasonably possible that impairments would need to be recognized. We performed a quantitative assessment of goodwill as of October 1, 2024 and determined there was no goodwill impairment.
Reworded paragraphs (27)
Previous wording
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 2,427 producing natural gas and oil wells (1,542.6 net to us) and we operate 1,747 of these wells.
Current wording
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.
Previous wording
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 $34.0 million as of December 31, 2024.
Current wording
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.
Previous wording
Prices for natural gas and oil have been highly volatile in recent years but we expect our natural gas production to increase, 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 2025 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 2025 and future periods. We may need to recognize 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.
Current wording
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.
Previous wording
Natural gas and oil sales. Natural gas and oil sales of $1.0 billion in 2024 decreased by $0.2 billion, or 17%, as compared to $1.3 billion in 2023. The decrease was primarily due to lower prices received for our natural gas production. Our 2024 natural gas production increased 1% to 527.5 Bcf (1.4 Bcf per day), which was sold at an average price of $1.98 per Mcf as compared to 524.5 Bcf (1.4 Bcf per day) sold at an average price of $2.40 in 2023.
Current wording
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.
Previous wording
Gas services revenues. Gas services revenues of $206.1 million in 2024 decreased $94.4 million (31%) from $300.5 million in 2023. 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. These activities commenced in 2022 with the acquisition of a pipeline and natural gas treating plant and the opportunity to utilize our excess transport capacity in North Louisiana. Gas services revenues decreased in 2024 due primarily to lower natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.
Current wording
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.
Previous wording
Production and ad valorem taxes. Our production and ad valorem taxes decreased $34.4 million (37%) to $57.4 million in 2024 from $91.8 million in 2023. This decrease was primarily related to a statutory decrease to the Louisiana production tax rate and lower Texas production taxes and ad valorem taxes related to lower natural gas prices in 2024.
Current wording
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.
Previous wording
Gathering and transportation. Gathering and transportation costs increased $10.0 million (5%) to $194.9 million in 2024 as compared to $184.9 million in 2023. This increase was due to production growth in areas with higher average gathering and transportation rates.
Current wording
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.
Previous wording
Lease operating expenses. Our lease operating expense of $130.5 million ($0.25 per Mcfe) in 2024 was $1.7 million, or 1% lower than lease operating expenses in 2023 of $132.2 million ($0.25 per Mcfe). The decrease in lease operating expense was due to lower water disposal costs and other production costs as compared to 2023.
Current wording
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.
Previous wording
Gas services expenses. Gas services expenses of $205.4 million in 2024 were $76.6 million (27%) lower than gas services expenses in 2023 of $282.1 million. The decrease was due primarily to lower natural gas prices for purchases of third-party natural gas for resale.
Current wording
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.
Previous wording
Depreciation, depletion and amortization expense ("DD&A"). DD&A expense increased $187.5 million (31%) to $795.4 million in 2024 from $607.9 million in 2023 and our DD&A expense per equivalent Mcf produced was $1.51 per Mcfe in 2024 as compared to $1.16 per Mcfe in 2023. The increase in DD&A rate was primarily due to lower estimated proved undeveloped reserves used in determining the DD&A rate, which resulted from the low natural gas price used in the estimation of proved reserves at December 31, 2024.
Current wording
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.
Previous wording
General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, increased to $39.4 million in 2024 from $38.0 million in 2023 due primarily to higher stock-based compensation. Stock-based compensation included in general and administrative expenses was $15.3 million and $9.9 million in 2024 and 2023, respectively.
Current wording
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.
Previous wording
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 $10.2 million for 2024 as compared to net gains on derivative financial instruments of $187.6 million for 2023. Realized net gains from our natural gas price risk management program were $207.8 million in 2024 as compared to $80.3 million of realized net gains in 2023. We recognized unrealized losses on derivative financial instruments of $197.6 million and unrealized gains of $107.3 million in 2024 and 2023, respectively.
Current wording
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.
Previous wording
Interest expense. Interest expense was $210.6 million for 2024 as compared to $169.0 million for 2023. 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 2024 totaled $11.5 million compared with $8.0 million for 2023. The increase in interest expense in 2024 was due primarily to the issuance of our 6.75% senior notes in 2024.
Current wording
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.
Previous wording
Income taxes. Our income tax benefit was $149.1 million in 2024 as compared to a provision of $35.1 million in 2023. Our effective tax rate of 41% in 2024 differed from the federal income tax rate of 21% due primarily to research and development and other tax credits claimed in 2024, changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes, including a reduction in the Louisiana state corporate tax rates. Our effective tax rate of 14% in 2023 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.
Current wording
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.
Previous wording
Net income. We reported a net loss available to common stockholders of $218.8 million or $(0.76) per diluted share in 2024 and net income available to common stockholders of $211.9 million or $0.76 per diluted share in 2023. The net loss in 2024 is primarily due to the impact of lower natural gas prices in 2024 and the unrealized loss on our derivative financial instruments of $197.6 million. Loss from operations in 2024 was $168.6 million as compared to income from operations of $226.6 million in 2023.
Current wording
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.
Previous wording
Cash flows from operating activities. Net cash provided by our operating activities decreased $396.5 million (39%) to $620.3 million in 2024 from $1.0 billion in 2023. The decrease was primarily due to the lower natural gas prices we realized in 2024.
Current wording
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.
Previous wording
Proceeds from asset sales. In 2024, we sold certain non-operated properties for net proceeds of $1.2 million. In 2023, we sold certain non-operated properties for net proceeds of $41.3 million.
Current wording
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.
Previous wording
Contributions from noncontrolling interest. In 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system. During 2024 and 2023, our noncontrolling partner contributed $60.5 million and $24.0 million, respectively, to the midstream partnership.
Current wording
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.
Previous wording
Capital expenditures. The decrease in capital expenditures of $373.6 million is primarily due to lower drilling and completion activities in 2024.
Current wording
Capital expenditures. The increase in capital expenditures of $258.8 million is primarily due to higher drilling and completion activities in 2025.
Previous wording
We currently expect to spend approximately $1.0 billion to $1.1 billion in 2025 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 $130 million to $150 million in our Western Haynesville midstream partnership. Under our 2025 operating plan, we currently expect to drill 46 operated horizontal wells (40.3 net) and to turn 46 operated wells (39.7 net) to sales in 2025.
Current wording
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.
Previous wording
As of December 31, 2024, we had $415.0 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 4.0 to 1.0, which reduces to 3.75 to 1.0 on June 30, 2025 and to 3.5 to 1.0 on September 30, 2025 and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of December 31, 2024.
Current wording
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.
Previous wording
As of December 31, 2024, we had $1.1 billion of liquidity, comprised of $1.1 billion of unused borrowing capacity under our bank credit facility and $6.8 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.
Current wording
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.
Previous wording
We expect to fund our future development and exploration activities with future operating cash flow. 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.
Current wording
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.
Previous wording
Our contractual obligations consist primarily of natural gas transportation and gathering contracts, principal and interest payments on our senior notes and bank credit facility and other operating lease obligations. Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $84.4 million for 2025, $91.6 million for 2026, $90.0 million for 2027, $82.9 million for 2028, $73.8 million for 2029 and $98.0 million for commitments thereafter. Interest payments under our senior notes and bank credit facility are $196.6 million for 2025 and 2026, $192.8 million for 2027, $166.3 million for 2028, $75.0 million for 2029 and $2.4 million for all periods thereafter.
Current wording
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.
Previous wording
On December 31, 2024, we had $743.0 million in U.S. federal net operating loss carryforwards and $1.8 billion in certain state net operating loss carryforwards. 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.
Current wording
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.
Previous wording
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 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 would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions.
Current wording
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.
Previous wording
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. 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 impairments in the carrying values of our proved and unproved natural gas and oil properties in the future.
Current wording
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.