COMSTOCK RESOURCES INC (CRK)

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 2,427 producing natural gas and oil wells (1,542.6 net to us) and we operate 1,747 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 $34.0 million as of December 31, 2024.

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.

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Results of Operations

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

Our operating data for the year ended December 31, 2024 and 2023 are summarized below:

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.

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:

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.

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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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

Discussions of 2023 items and year-to-year comparisons between 2023 and 2022 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, 2023 filed with the SEC on February 16, 2024.

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Cash Flows, Liquidity and Capital Resources

Cash Flows

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

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.

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.

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.

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.

Capital expenditures. The decrease in capital expenditures of $373.6 million is primarily due to lower drilling and completion activities in 2024.

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Our capital expenditures are summarized in the following table:

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.

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.

Liquidity and Capital Resources

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.

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.

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

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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.

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.

Federal and State Taxation

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.

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.

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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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.

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.

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.

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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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 2,478 producing natural gas and oil wells (1,516.7 net to us) and we operate 1,703 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 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 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 $30.8 million as of December 31, 2023.

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 2024 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 2024 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 becomes insufficient to recover their carrying value.

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Results of Operations

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

Our operating data for the year ended December 31, 2023 and 2022 are summarized below:

Natural gas and oil sales. Natural gas and oil sales of $1.3 billion in 2023 decreased by $1.9 billion, or 60%, as compared to $3.1 billion in 2022. The decrease was primarily due to lower prices received for our natural gas production. Our 2023 natural gas production increased 5% to 524.5 Bcf (1.4 Bcf per day), and was sold at an average price of $2.40 per Mcf as compared to 500.6 Bcf (1.4 Bcf per day) sold at an average price of $6.23 in 2022.

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:

Gas services revenues. Gas services revenues of $300.5 million in 2023 decreased $202.9 million (40%) from $503.4 million in 2022. 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 2023 due primarily to lower natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.

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Production and ad valorem taxes. Our production and ad valorem taxes increased $13.9 million (18%) to $91.8 million in 2023 from $77.9 million in 2022. This increase was primarily related to increases in the Louisiana production tax rate and higher ad valorem taxes.

Gathering and transportation. Gathering and transportation costs increased $29.2 million (19%) to $184.9 million in 2023 as compared to $155.7 million in 2022. This increase was due to production growth in areas with higher average gathering and transportation rates.

Lease operating expenses. Our lease operating expense of $132.2 million ($0.25 per Mcfe) in 2023 was $21.1 million, or 19%, higher than lease operating expenses in 2022 of $111.1 million ($0.22 per Mcfe). The increase in lease operating expense was due to higher production and increased water disposal costs and other production costs.

Gas services expenses. Gas services expenses of $282.1 million in 2023 were $183.0 million (39%) lower than gas services expenses in 2022 of $465.0 million. The decrease was due primarily to lower natural gas prices for purchases of third party natural gas for resale.

Depreciation, depletion and amortization expense ("DD&A"). DD&A expense increased $118.5 million (24%) to $607.9 million in 2023 from $489.5 million in 2022 and our DD&A expense per equivalent Mcf produced was $1.16 per Mcfe in 2023 as compared to $0.98 per Mcfe in 2022. The increase in DD&A rate was primarily due to higher drilling and completion costs incurred for wells turned to sales in 2023 combined with lower estimated proved reserves resulting from the low natural gas price used in the determination of proved reserves at December 31, 2023.

General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, decreased to $38.0 million in 2023 from $39.4 million in 2022 due primarily to lower personnel costs. Stock-based compensation included in general and administrative expenses was $9.9 million and $6.6 million in 2023 and 2022, respectively.

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 $187.6 million for 2023 as compared to net losses on derivative financial instruments of $662.5 million for 2022. Realized net gains from our natural gas price risk management program were $80.3 million in 2023 as compared to $862.7 million of realized net losses in 2022. We recognized unrealized gains on derivative financial instruments of $107.3 million and $200.2 million in 2023 and 2022, respectively.

Interest expense. Interest expense was $169.0 million for 2023 as compared to $171.1 million for 2022. 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 2023 totaled $8.0 million compared with $10.3 million for 2022. The decrease in interest expense in 2023 was due primarily to the retirement of our 7.5% senior notes in 2022.

Loss on early retirement of debt. During 2022, we retired $244.4 million principal amount of our 7.5% senior notes and $26.1 million principal amount of our 6.75% senior notes. As a result of premiums paid over face value and costs associated with the retirements, we recognized a loss on early retirement of debt of $46.8 million during 2022.

Income taxes. Our income tax provision was $35.1 million and $261.1 million in 2023 and 2022, respectively. Our effective tax rate of 14% in 2023 and 19% in 2022 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 available to common stockholders of $211.9 million or $0.76 per diluted share in 2023 and a net income available to common stockholders of $1.1 billion or $4.11 per diluted share in 2022. The decrease in net income in 2023 is primarily due to the impact of lower natural gas prices in 2023. Income from operations in 2023 decreased to $226.6 million as compared to $2.3 billion in 2022.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Discussions of 2022 items and year-to-year comparisons between 2022 and 2021 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, 2022 filed with the SEC on February 17, 2023.

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Cash Flows, Liquidity and Capital Resources

Cash Flows

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

Cash flows from operating activities. Net cash provided by our operating activities decreased $681.5 million (40%) to $1.0 billion in 2023 from $1.7 billion in 2022. The decrease was primarily due to the lower realized natural gas prices we had in 2023.

Proceeds from asset sales. In 2023, we sold certain non-operated properties for net proceeds of $41.3 million. In 2022, we sold certain non-operated properties for net proceeds of $4.2 million.

Contributions from noncontrolling interest. During the fourth quarter of 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system over the next several years. During 2023, the noncontrolling interest contributed $24.0 million to the midstream partnership.

Capital expenditures. The increase in capital expenditures of $357.2 million is primarily due to higher drilling, completion and acquisition activities in 2023.

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Our capital expenditures are summarized in the following table:

We currently expect to spend approximately $750 million to $850 million in 2024 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 $125.0 million to $150.0 million in our Western Haynesville midstream partnership. Under our 2024 operating plan, we currently expect to run five operated drilling rigs and to drill 46 operated horizontal wells (35.9 net) and to turn 44 operated wells (38.2 net) to sales in 2024.

Retirement of senior notes. In 2022, we retired all of our outstanding 7.5% senior notes due in 2025 for $248.9 million, which included premiums paid over face value of $4.5 million, and we retired $26.1 million principal amount of our 6.75% senior notes for $24.9 million.

Common stock and preferred stock dividends. In 2023, we paid a quarterly cash dividend of 12.5¢ per share of common stock. On December 15, 2022, we paid a cash dividend of 12.5¢ per share of common stock. On November 30, 2022, all of the outstanding shares of our Series B Redeemable Convertible Preferred Stock were converted into 43,750,000 shares of common stock.

Debt issuance costs. In 2022, we entered into a new five-year bank credit facility and we incurred $10.8 million of issuance costs associated with the new bank credit facility

Liquidity and Capital Resources

As of December 31, 2023, we had $480.0 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 1.75% to 2.75% or an alternate base rate plus 0.75% to 1.75%, 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, 2023.

As of December 31, 2023, we had $1.0 billion of liquidity, comprised of $1.0 billion of unused borrowing capacity under our bank credit facility and $16.7 million of cash and cash equivalents on hand. Our short and long-term capital

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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. 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.

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 $97.8 million for 2024, $89.6 million for 2025, $63.9 million for 2026, $62.7 million for 2027, $56.3 million for 2028 and $96.4 million for commitments thereafter. Interest payments under our senior notes and bank credit facility are $175.1 million for 2024 through 2026, $170.6 million for 2027, $139.3 million for 2028 and $72.8 million for all periods thereafter.

Federal and State Taxation

At December 31, 2023, we had $754.1 million in U.S. federal net operating loss carryforwards and $1.7 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.

Our federal income tax returns for the years subsequent to December 31, 2019 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, 2020. 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.

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, including certain general and administrative expenses. 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 and we do not capitalize any of our general and administrative expenses.

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

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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.

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.

Goodwill. We have goodwill of $335.9 million as of December 31, 2023 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.

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, 2023 and determined there was no goodwill impairment.

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 net operating loss 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

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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 net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. We will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future reporting periods.

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 oil and natural gas 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 2,393 producing oil and natural gas wells (1,464.7 net) and we operate 1,633 of these wells.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas 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 oil and natural gas at current market prices at the point 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 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 oil and natural gas 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, oil and natural gas, 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 oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $29.1 million as of December 31, 2022.

Prices for oil and natural gas 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 2023 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 2023 and future periods. We may need to recognize impairments of our oil and natural gas properties if oil and natural gas prices decline, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value.

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Results of Operations

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Our operating data for the year ended December 31, 2022 and 2021 are summarized below:

Natural gas and oil sales.  Natural gas and oil sales of $3.1 billion in 2022 increased by $1.3 billion, or 69%, as compared to $1.9 billion in 2021. The increase was primarily due to higher prices received for our natural gas production and increased natural gas production. Our 2022 natural gas production was 500.6 Bcf (1.4 Bcf per day), which was sold at an average price of $6.23 per Mcf as compared to 489.3 Bcf (1.3 Bcf per day) sold at an average price of $3.63 in 2021. In October 2021, we sold our Bakken shale properties, which represented most of our oil production.

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

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Gas services revenues. Gas services revenues of $503.4 million in 2022 include sales of natural gas purchased from unaffiliated third parties for resale and fees received from unaffiliated third parties for natural gas transportation and treating services. These activities commenced in 2022 with the acquisition of a pipeline and gas treating plant and the opportunity to utilize our excess transport capacity in North Louisiana.

Production and ad valorem taxes.  Our production and ad valorem taxes increased $28.8 million (59%) to $77.9 million in 2022 from $49.1 million in 2021. This increase was primarily related to the increase in natural gas sales and higher production tax rates enacted in the state of Louisiana during 2022.

Gathering and transportation.  Gathering and transportation costs increased $24.7 million (19%) to $155.7 million in 2022 as compared to $130.9 million in 2021. This increase was due to higher average transportation rates including higher value of fuel used to transport our natural gas during 2022.

Lease operating expenses.  Our lease operating expense of $111.1 million in 2022 was $7.7 million or 7% higher than the lease operating expenses in 2021 of $103.5 million due to higher natural gas production. Our lease operating expense of $0.22 per Mcfe produced for 2022 was comparable to the 2021 rate of $0.21 per Mcfe.

Gas services expenses. Gas services expenses were $465.0 million during 2022, which include the cost of unaffiliated third party natural gas purchased for resale and the operating expenses of the pipeline and natural gas treating plant acquired in 2022.

Depreciation, depletion and amortization expense ("DD&A").  DD&A expense increased $20.1 million (4%) to $489.5 million in 2022 from $469.4 million in 2021 and our DD&A expense per equivalent Mcf produced was $0.98 per Mcfe in 2022 as compared to $0.95 per Mcfe in 2021. The increase in DD&A rate was primarily due to higher drilling costs incurred in 2022.

General and administrative expenses.  General and administrative expense, which is reported net of overhead reimbursements, increased to $39.4 million in 2022 from $34.9 million in 2021 due primarily to higher personnel costs. Stock-based compensation included in general and administrative expense was $6.6 million and $6.8 million in 2022 and 2021, respectively.

Gain (loss) on sale of assets. We reported a gain on the sale of assets in 2022 of $0.3 million, which was primarily related to the sale of certain nonstrategic, non-operated natural gas and oil properties. We reported a loss on the sale of assets of $162.1 million for 2021 which was primarily related to our divestiture of our Bakken shale assets in November 2021.

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 losses on derivative financial instruments of $662.5 million for 2022 as compared to $560.6 million for 2021. Realized net losses from our oil and natural gas price risk management program were $862.7 million in 2022 as compared to $419.9 million in 2021. We recognized unrealized gains on derivative financial instruments in 2022 of $200.2 million and unrealized losses of $140.9 million in 2021.

Interest expense.  Interest expense was $171.1 million for 2022 as compared to $218.5 million for 2021. 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 2022 totaled $10.3 million compared with $21.7 million for 2021. The decrease in interest expense in 2022 was due primarily to the refinancing of our senior notes in 2021, the early retirements of senior notes in May and June 2022 and the repayment of borrowings under our bank credit facility.

Loss on early retirement of debt. During 2022, we retired $244.4 million principal amount of our 7.5% senior notes and $26.1 million principal amount of our 6.75% senior notes. In 2021, we refinanced $375.0 million principal amount of our 7.5% senior notes and $1.65 billion principal amount of our 9.75% senior notes. As a result of premiums paid over face value and costs associated with the retirements and repurchases, we recognized a loss on early retirement of debt of $46.8 million and $352.6 million during 2022 and 2021, respectively.

Income taxes.  Our income tax provision was $261.1 million and $11.4 million in 2022 and 2021, respectively. Our effective tax rate of 19% in 2022 and (5)% in 2021 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 available to common stockholders of $1.1 billion or $4.11 per diluted share in 2022 and a net loss available to common stockholders of $259.2 million or $1.12 per diluted share in 2021. The net income in 2022 is primarily due to our higher natural gas and oil sales. Income from operations in 2022 increased to $2.3 billion as compared to $900.8 million in 2021.

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Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Discussions of 2021 items and year-to-year comparisons between 2021 and 2020 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, 2021 filed with the SEC on February 17, 2022.

Cash Flows, Liquidity and Capital Resources

Cash Flows

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

Cash flows from operating activities. Net cash provided by our operating activities increased $839.4 million (98%) to $1,698.4 million in 2022 from $859.0 million in 2021. The increase was primarily due to higher realized natural gas prices in 2022.

Proceeds from asset sales. In 2022, we sold certain non-operated properties for net proceeds of $4.1 million. In 2021, we sold our non-operated properties in the Bakken shale and certain other properties for $138.4 million after selling expenses.

Issuance of new senior notes and retirement of senior notes. In 2022, we retired all of our outstanding 7.5% senior notes due in 2025 for $248.9 million, which included premiums paid over face value of $4.5 million, and we retired $26.1 million principal amount of our 6.75% senior notes for $24.9 million. In 2021, we issued $1.25 billion principal amount of 6.75% senior notes due in 2029 and $965.0 million principal amount of 5.875% senior notes due in 2030. The proceeds from the note offerings were used to redeem $2,025.0 million principal amount of outstanding senior notes for $2,198.1 million, including premiums paid over face value and costs related to a tender offer.

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Capital expenditures. The increase in capital expenditures of $412.7 million is primarily due to higher drilling, completion and acquisition activities in 2022.

Our capital expenditures are summarized in the following table:

We currently expect to spend approximately $950 million to $1.15 billion in 2023 on our development and exploration projects primarily focused on the continued development of our Haynesville/Bossier shale properties including our exploration and development of our Western Haynesville acreage. We also expect to spend $75 million to $125 million on infrastructure, including upgrades to our Western Haynesville pipeline and processing facilities, and for other development costs. Under our current operating plan, we expect to drill 67 operated horizontal wells (50.5 net) and to turn 69 wells (49.2 net) to sales in 2023. The Company also expects to spend an additional $25 million to $35 million on acquiring acreage in 2023.

Common stock and preferred stock dividends. On December 15, 2022, we paid a cash dividend of $0.125 per share of common stock. On November 30, 2022, all of the outstanding shares of our Series B Redeemable Convertible Preferred Stock were converted into 43,750,000 shares of common stock.

Debt issuance costs. In 2022, we entered into a new five-year bank credit facility and we incurred $10.8 million of issuance costs associated with the new bank credit facility. In 2021, we incurred $35.6 million of debt issuance costs primarily due to the issuance of our 6.75% senior notes and 5.875% senior notes.

Liquidity and Capital Resources

On November 15, 2022, we entered into an amended and restated bank credit facility with Wells Fargo Bank National Association as administrative agent, and other participating banks. Aggregate commitments under the new credit facility were $1.5 billion and mature on November 15, 2027. Borrowings under the new bank credit facility are subject to a borrowing base, which was initially 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 subsidiaries and bear interest at our option, at either adjusted SOFR plus 1.75% to 2.75% or an alternate base rate plus 0.75% to 1.75%, 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 borrowing base. There were no outstanding borrowings as of December 31, 2022. The 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 December 31, 2022.

As of December 31, 2022, we had $1.6 billion of liquidity, comprised of $1.5 billion of unused borrowing capacity under our bank credit facility and $54.7 million of cash and cash equivalents on hand. Our short and long-term capital requirements

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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. 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, oil and natural gas 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.

Our contractual obligations consist primarily of natural gas transportation and gathering contracts and drilling and completion contracts. Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $57.0 million for 2023, $57.5 million for 2024, $45.7 million for 2025, $40.9 million for 2026, $40.7 million for 2027 and $124.3 million for commitments thereafter. Terms of drilling contracts vary from well to well, or are for periods ranging from less than one year to three years. Existing commitments under drilling contracts are $34.9 million for 2023 and 2024, $36.7 million for 2025, $31.9 million for 2026 and $1.8 million for 2027. In 2021 and 2022, we entered into hydraulic fracturing services agreements for exclusive use of two natural gas powered hydraulic fracturing fleets. Commitments under these contracts are $33.7 million for 2023, $38.5 million for 2024, $24.3 million for 2025 and $4.7 million for 2026.

Federal and State Taxation

At December 31, 2022, we had $909.9 million in U.S. federal net operating loss carryforwards and $1.5 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 $766.2 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, 2018 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, 2018. 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.

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 oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas 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 and we do not capitalize any of our general and administrative expenses.

Oil and natural gas reserve quantities.  The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas 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 oil and natural gas 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 oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas 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.

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The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas 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.

Impairment of oil and gas 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 oil and natural gas 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 oil and natural gas 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 oil and gas leases. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to its oil and gas 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 oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, 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 oil and gas properties in the future.

Goodwill.  We have goodwill of $335.9 million as of December 31, 2022 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.

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, 2022 and determined there was no goodwill impairment.

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 net operating loss 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 net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. 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.

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 oil and natural gas 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 2,557 producing oil and natural gas wells (1,459.6 net) and we operate 1,575 of these wells. We intend to maintain an operating plan in 2022 targeting additional debt reduction and generation of free cash flow.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire seismic data, 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 oil and natural gas at current market prices at the point 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 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, oil and natural gas. Oil and 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 oil and natural gas 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, oil and natural gas, 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 oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $25.7 million as of December 31, 2021.

Prices for oil and natural gas 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 resulting from the new wells we plan to drill in 2022 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 2022 and future periods. We may need to recognize impairments if oil and natural gas prices decline, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value.

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Results of Operations

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Our operating data for the year ended December 31, 2021 and 2020 are summarized below:

Oil and gas sales.  Oil and gas sales of $1.9 billion in 2021 increased $992.5 million or 116% over oil and gas sales in 2020 of $858.2 million. The increase is due to a 9% increase in our natural gas production along with a 99% increase in realized oil and natural gas prices in 2021. Our 2021 natural gas production was 489.3 billion cubic feet ("Bcf") (1.3 Bcf per day), which was sold at an average price of $3.63 per Mcf as compared to 450.8 Bcf (1.2 Bcf per day) sold at an average price of $1.80 in 2020. Our 2021 oil production was 1.2 MMBbls (3,315 Bbls per day), which was sold at an average price of $61.95 per Bbl as compared to 1.5 MMBbls (4,120 Bbls per day) sold at an average price of $32.36 per Bbl in 2020.

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

Production and ad valorem taxes.  Our production and ad valorem taxes increased $12.2 million (33%) to $49.1 million in 2021 from $37.0 million in 2020. This increase is primarily related to the increase in oil and natural gas sales in 2021.

Gathering and transportation.  Gathering and transportation costs increased $24.4 million or 23% to $130.9 million in 2021 as compared to $106.6 million in 2020. This increase was due primarily to the higher natural gas production in 2021 combined with a higher average rate.

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Lease operating expenses.  Our lease operating expense of $103.5 million in 2021 was $1.0 million or 1% higher than the lease operating expenses in 2020 of $102.5 million due to the higher natural gas production. Our lease operating expense of $0.21 per Mcfe produced for 2021 was comparable to the 2020 rate of $0.22 per Mcfe.

Depreciation, depletion and amortization expense ("DD&A").  DD&A increased $52.3 million (13%) to $469.4 million in 2021 from $417.1 million in 2020 and our DD&A per equivalent Mcf produced was $0.95 per Mcfe in 2021 as compared to $0.91 per Mcfe in 2020. The increase in DD&A is primarily due to the 9% increase in natural gas production.

General and administrative expenses.  General and administrative expense, which is reported net of overhead reimbursements, increased to $34.9 million in 2021 from $32.0 million in 2020 due primarily to higher personnel costs. Stock-based compensation was $6.8 million and $6.5 million in 2021 and 2020, respectively.

Loss on sale of assets. We reported a loss on the sale of assets of $162.1 million for 2021 which was primarily related to our divestiture of our Bakken shale assets. In November 2021, we divested our assets in the Bakken shale for net proceeds of $138.1 million in cash.

Derivative financial instruments.  We use derivative financial instruments as part of our price risk management program to protect our capital investments. We had net losses on derivative financial instruments of $560.6 million for 2021 as compared to net gains of $10.0 million for 2020. Realized net losses from our oil and natural gas price risk management program were $419.9 million in 2021 as compared to realized net gains of $134.9 million in 2020. Realized gains from our interest rate risk management program were $163 thousand in 2021 as compared to realized losses of $389 thousand in 2020. Unrealized losses on derivative financial instruments were $140.9 million in 2021 and $124.5 million in 2020.

Interest expense.  Interest expense was $218.5 million for 2021 as compared to $234.8 million for 2020. Included in interest expense was amortization of the discount on our senior notes and the debt cost amortization associated with our outstanding debt. The non-cash interest expense for 2021 totaled $21.7 million compared with non-cash interest expense of $34.0 million for 2020. The decrease in interest expense for 2021 is due primarily to the retirement of our 9.75% and 7.50% senior notes during 2021.

Loss on early retirement of debt. We repurchased $375.0 million principal amount of our 7.50% senior notes and $1.65 billion principal amount of our 9.75% senior notes in 2021. As a result of premiums paid over face value and costs associated with the repurchases, we recognized a loss on early retirement of debt of $352.6 million during 2021. During 2020, we exchanged 767,096 shares of our common stock to retire $5.6 million aggregate principal amount of our 7.50% senior notes and recognized a $861 thousand loss on early retirement of debt.

Income taxes.  Income taxes were a provision of $11.4 million in 2021 and a benefit of $9.2 million in 2020. The effective tax rate of -5% in 2021 and 15% in 2020 differed from the federal income tax rate of 21% primarily due to the impact of an increase to our valuation allowance on our federal and state net operating loss carryforwards and due to higher state current taxes.

Net income.  We reported a net loss available to common stockholders of $259.2 million or $1.12 per diluted share in 2021 and net loss available to common stockholders of $83.4 million or $0.39 per diluted share in 2020. The net loss in 2021 is primarily due to losses on derivative financial instruments of $560.6 million, the loss on early retirement of debt of $352.6 million and the $162.2 million loss on the Bakken shale divestiture. Income from operations in 2021 was $900.8 million.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

Discussions of 2020 items and year-to-year comparisons between 2020 and 2019 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, 2020 filed with the SEC on February 17, 2021.

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Cash Flows, Liquidity and Capital Resources

Cash Flows

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

Cash flows from operating activities. Net cash provided by our operating activities increased $283.3 million (49%) to $859.0 million in 2021 from $575.7 million in 2020. The increase is primarily due to the 9% increase in our natural gas production and improved oil and natural gas prices in 2021.

Proceeds from asset sales. In 2021, we sold our non-operated properties in the Bakken shale and certain other properties for $138.4 million after selling expenses. The Bakken shale properties sold included non-operated interests in 442 producing wells (68.3 net) producing approximately 4,500 barrels of oil equivalent per day.

Issuance of common stock. In 2020, we sold 41,325,000 shares of common stock in an unwritten public offering and used the net proceeds of $196.4 million to substantially fund the redemption of our Series A convertible preferred stock for $210.0 million.

Issuance of new senior notes and retirement of senior notes. In March and June 2021, we issued $1.25 billion and $965.0 million principal amount of 6.75% senior notes due 2029 (the "2029 Notes") and 5.875% senior notes due 2030 (the "2030 notes"), respectively, in private placement offerings. The 2029 Notes mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year. The 2030 Notes mature on January 15, 2030 and accrue interest at a rate of 5.875% per annum, payable semi-annually on January 15 and July 15 of each year. The proceeds from the offerings were used to repurchase $375.0 million principal amount of our 7.5% senior notes due 2025 and to repurchase $1.65 billion principal amount of our 9.75% senior notes due 2026. The redemption of the senior notes included $171.9 million in premiums paid over face value, accrued interest of $44.2 million and $1.1 million of costs related to the offerings. In 2020, we issued $800.0 million principal amount of our 9.75% Senior Notes due 2026 in an underwritten public offering and received net proceeds of $737.1 million. The proceeds were used to reduce amounts outstanding under our bank credit facility.

Capital expenditures. The increase in capital expenditures of $179.5 million is primarily due to higher drilling, completion and acquisition activities in 2021. We spent $57.7 million in 2021 to acquire approximately 49,000 net undeveloped acres prospective for the Haynesville and Bossier shale through acquisitions or direct leasing. In 2020, we acquired 13,519 net acres for $7.9 million.

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Our capital expenditures are summarized in the following table:

We currently expect to spend approximately $750 million to $800 million in 2022 on our development and exploration projects primarily focused on the continued development of our Haynesville/Bossier shale properties, which includes $60 million to $65 million on infrastructure, workovers and other development costs. Under our current operating plan, we expect to drill 67 operated horizontal wells (52.1 net) and to turn 69 wells (56.0 net) to sales in 2022. The Company also expects to spend an additional $8 million to $12 million on leasing activities in 2022.

Liquidity and Capital Resources

As of December 31, 2021, we had $1.2 billion of liquidity, comprised of $1.17 billion of unused borrowing capacity under our bank credit facility and $30.7 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. The timing of most of our capital expenditures is discretionary because we have no 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. 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, oil and natural gas 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.

Our contractual obligations consist primarily of natural gas transportation and gathering contracts and drilling and completion contracts. Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $41.2 million for 2022, $41.5 million for 2023, $41.6 million for 2024, $29.8 million for 2025, $25.0 million for 2026 and $24.8 million for 2027 through 2030. Terms of drilling contracts vary from well to well, or are for periods of less than one year. Existing commitments under drilling contracts is $12.3 million for 2022. In 2021, the Company entered into a well stimulation agreement that extends to 2024 for exclusive use of a natural gas powered pressure pumping fleet. The minimum commitment under this contract is $19.2 million per year from 2022 through 2024.

As of December 31, 2021, we had $235.0 million outstanding under our bank credit facility that matures on July 16, 2024. The borrowing base, which is currently set at $1.4 billion, 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 subsidiaries and bear interest at our option, at either LIBOR plus 2.25% to 3.25% or a 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

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the borrowing base. The 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 4.0 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, 2021.

Federal and State Taxation

At December 31, 2021, we had $906.6 million in U.S. federal net operating loss carryforwards and $1.5 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 generally limited to an annual amount based on the fair market value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate. Our NOLs are estimated to be limited to $3.3 million a year as a result of this limitation. In addition to this limitation, IRC Section 382 provides that a corporation with a net unrealized built-in gain immediately before an ownership change may increase its limitation by the amount of built-in gain recognized during a recognition period, which is generally the five-year period immediately following an ownership change. Based on the fair market value of our common stock immediately prior to the ownership change, we believe that we have a net unrealized built-in gain which will increase the Section 382 limitation during the five-year recognition period from 2018 to 2023 by $117.0 million.

NOLs that exceed the Section 382 limitation in any year continue to be allowed as carryforwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. NOLs incurred prior to 2018 generally have a 20-year life until they expire. NOLs generated in 2018 and after would be carried forward indefinitely. Our use of new NOLs arising after the date of an ownership change would not be affected by the 382 limitation. 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 $834.6 million of the U.S. federal NOL carryforwards and $1.3 billion of the estimated state NOL carryforwards will expire unused.

Our federal income tax returns for the years subsequent to December 31, 2017 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, 2018. We currently 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.

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 oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas 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 and we do not capitalize any of our general and administrative expenses.

Oil and natural gas reserve quantities.  The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas 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 oil and natural gas 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 oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas 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 oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas 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

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changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

Impairment of oil and gas 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 oil and natural gas 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 oil and natural gas 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 oil and gas leases. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to its oil and gas 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 oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, 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 oil and gas properties in the future.

Goodwill.  We have goodwill of $335.9 million as of December 31, 2021 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.

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, 2021 and determined there was no goodwill impairment.

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 net operating loss 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 net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. 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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