COMSTOCK RESOURCES INC 10-K

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. 29 COMSTOCK RESOURCES, INC. 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: Year Ended December 31, 2022 2021 (In thousands except per unit amounts) Net Production Data: Natural gas (MMcf) 500,616 489,274 Oil (MBbls) 82 1,210 Natural gas equivalent (MMcfe) 501,107 496,534 Revenues: Natural gas sales $ 3,117,094 $ 1,775,768 Oil sales 7,597 74,962 Total natural gas and oil sales $ 3,124,691 $ 1,850,730 Gas services $ 503,366 $ — Expenses: Production and ad valorem taxes $ 77,917 $ 49,141 Gathering and transportation $ 155,679 $ 130,940 Lease operating $ 111,134 $ 103,467 Exploration $ 8,287 $ — Gas services $ 465,044 $ — Average Sales Price: Natural gas (per Mcf) $6.23 $3.63 Oil (per Bbl) $92.65 $61.95 Average equivalent (Mcfe) $6.24 $3.73 Expenses ($ per Mcfe): Production and ad valorem taxes $0.16 $0.10 Gathering and transportation $0.31 $0.26 Lease operating $0.22 $0.21 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: Year Ended December 31, 2022 2021 Average Realized Natural Gas Price: Natural gas, per Mcf $ 6.23 $ 3.63 Cash settlements on derivative financial instruments, per Mcf (1.73) (0.84) Price per Mcf, including cash settlements on derivative financial instruments $ 4.50 $ 2.79 Average Realized Oil Price: Crude oil per Bbl $ 92.65 $ 61.95 Cash settlements on derivative financial instruments, per Bbl — (6.67) Price per Bbl, including cash settlements on derivative financial instruments $ 92.65 $ 55.28 30 COMSTOCK RESOURCES, INC. 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. 31 COMSTOCK RESOURCES, INC. 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: Year Ended December 31, 2022 2021 (in thousands) Sources of cash and cash equivalents: Operating activities $ 1,698,388 $ 859,005 Proceeds from asset sales 4,186 138,394 Issuance of new senior notes — 2,222,500 Total $ 1,702,574 $ 3,219,899 Uses of cash and cash equivalents: Capital expenditures $ 1,101,869 $ 689,210 Retirement of senior notes 273,920 2,210,626 Repayments on bank credit facility, net of borrowings 235,000 265,000 Common stock dividends 34,688 — Preferred stock dividends 16,014 17,500 Debt issuance costs 10,839 35,604 Other 6,255 1,568 Total $ 1,678,585 $ 3,219,508 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. 32 COMSTOCK RESOURCES, INC. 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: Year Ended December 31, 2022 2021 (in thousands) Acquisitions: Proved property $ 500 $ 21,781 Unproved property 54,120 35,871 Exploration and development: Developmental leasehold costs 13,727 12,953 Exploratory drilling and completion costs 63,520 6,966 Development drilling and completion costs 901,026 569,141 Other development costs 53,693 39,168 Asset retirement obligations 686 5,608 Total exploration and development 1,087,272 691,488 Other property 18,775 192 Total capital expenditures $ 1,106,047 $ 691,680 Change in accrued capital expenditures and other (37,561) 3,138 Prepaid drilling costs 34,069 — Asset retirement obligations (686) (5,608) Total cash capital expenditures $ 1,101,869 $ 689,210 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 33 COMSTOCK RESOURCES, INC. 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. 34 COMSTOCK RESOURCES, INC. 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. 35 COMSTOCK RESOURCES, INC.