Summary of Significant Accounting Policies (Policies)	12 Months Ended
Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Nature of Operations	Basis of Presentation and Nature of Operations Coterra Energy Inc. and its subsidiaries (“Coterra” or the “Company”) are engaged in the development, exploration and production of oil, natural gas and NGLs exclusively within the continental U.S. The Company's exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. The Company operates in one segment, oil and natural gas development, exploration and production. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company's entire portfolio without regard to geographic areas. The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders' equity, net income or cash flows. The Company (formerly known as Cabot Oil & Gas Corporation) and Cimarex Energy Co. (“Cimarex”) completed a merger transaction on October 1, 2021 (the “Merger”), pursuant to an agreement entered into by the Company and Cimarex (the “Merger Agreement”). Upon the effectiveness of the Merger, each eligible share of Cimarex common stock was automatically converted into the right to receive 4.0146 shares of the Company’s common stock. The transaction has been accounted for using the acquisition method of accounting, with the Company being treated as the accounting acquirer. Refer to Note 2, “Acquisitions,” for further information. Additionally, on October 1, 2021, Cabot Oil & Gas Corporation changed its name to Coterra Energy Inc.
Recently Issued and Adopted Accounting Pronouncements	Recently Issued and Adopted Accounting Pronouncements Convertible Instruments. In August 2020, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity ("ASU 2020-06"), which simplifies the accounting for convertible instruments by removing the separation models for (1) convertible debt with a cash conversion feature and (2) convertible instruments with a beneficial conversion feature. As a result, a convertible debt instrument will be accounted for as a single liability measured at its amortized cost. ASU 2020-06 also requires the application of the if-converted method for calculating diluted earnings per share for all convertible instruments and the treasury stock method will no longer be available. For public companies, the guidance is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. Early adoption is permitted in the first quarter of 2021. The Company elected to adopt the guidance in ASU 2020-06 as of October 1, 2021. The adoption of ASU 2020-06 did not have any effect on the Company’s financial positions, results of operations or cash flows; however, it modified certain disclosures, which were not material.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in four financial institutions at December 31, 2021. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal. From time to time, the Company may be in the position of a book overdraft in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable in the Consolidated Balance Sheet, and classifies the change in accounts payable associated with book overdrafts as an operating activity in the Consolidated Statement of Cash Flows. There was no book overdraft within accounts payable as of December 31, 2021 and 2020.
Restricted Cash	Restricted Cash Restricted cash includes cash that is legally or contractually restricted as to withdrawal or usage. As of December 31, 2021 and 2020, the restricted cash balance of $10 million and $12 million, respectively, includes cash deposited in escrow accounts that are restricted for use.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts The Company records an allowance for doubtful accounts based on the Company's estimate of future expected credit losses on outstanding receivables.
Inventories	Inventories Inventories are comprised of tubular goods and well equipment and are carried at average cost. Inventories are assessed periodically for obsolescence.
Properties and Equipment	Properties and Equipment Oil and Gas Properties The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized. Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the Consolidated Statement of Operations in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether reserves have been found only as long as: (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense. Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. Costs of sold or abandoned properties that make up a part of an amortization base (partial field) remain in the amortization base if the units-of-production rate is not significantly affected. If significant, a gain or loss, if any, is recognized and the sold or abandoned properties are retired. A gain or loss, if any, is also recognized when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold. The Company evaluates its proved oil and gas properties for impairment whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil. Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to the Company's undeveloped acreage amortization based on past drilling and exploration experience, the Company's expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Fixed Assets Fixed assets consist primarily of gas gathering systems, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years.
Asset Retirement Obligations	Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the units-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in depreciation, depletion and amortization expense in the Consolidated Statement of Operations.
Derivative Instruments	Derivative Instruments The Company enters into financial derivative contracts, primarily collars, swaps, roll differential swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future production volumes. The Company’s credit agreement restricts the ability of the Company to enter into financial commodity derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. The Company has elected not to designate its financial derivative instruments as accounting hedges under the accounting guidance. The Company evaluates all of its physical purchase and sale contracts to determine if they meet the definition of a derivative. For contracts that meet the definition of a derivative, the Company may elect the normal purchase normal sale (“NPNS”) exception provided under the applicable accounting guidance and account for the contract using the accrual method of accounting. Contracts that do not qualify for or for which the Company elects not to apply the NPNS exception are accounted for at fair value. All derivatives, except for derivatives that qualify for the NPNS exception, are recognized on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked to market. As a result, changes in the fair value of derivatives are recognized in operating revenues in gain (loss) on derivative instruments. The resulting cash flows are reported as cash flows from operating activities.
Leases	Leases The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in operating lease right-of-use assets (“ROU assets”) and operating and financing lease liabilities (current and non-current) in the Consolidated Balance Sheet. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company uses its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company has elected the following practical expedients in applying authoritative guidance on lease accounting: •For all operating leases, lease and non-lease components are accounted for as a single lease component. •Short-term leases (a lease that, at commencement, has a lease term of one year or less and does not contain a purchase option that the Company is reasonably certain to exercise) are not recognized in ROU assets and lease liabilities. •Certain land easements in existence prior to January 1, 2019 were not reassessed under new accounting guidance.
Fair Value of Assets and Liabilities	Fair Value of Assets and Liabilities The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows: •Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets. •Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. •Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in the valuation should be chosen.
Revenue Recognition	Revenue Recognition The Company’s revenue is typically generated from contracts to sell oil, natural gas and NGLs produced from interests in oil and gas properties owned by the Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that is either fixed or variable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. These contracts frequently meet the definition of a derivative under Accounting Standards Codification (“ASC”) 815, and are accounted for as derivatives unless the Company elects to treat them as normal sales as permitted under that guidance. The Company typically elects to treat contracts to sell oil, natural gas and NGL production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred. Gain or loss on derivative instruments is outside the scope of the revenue recognition standard and is not considered revenue from contracts with customers under that guidance. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue. Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. Under this method, a natural gas imbalance liability is recorded if the Company's excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties at the actual price realized upon the gas sale. A receivable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2021 and 2020 were not material. Practical Expedients. The Company makes use of certain practical expedients provided under the revenue standard, including the value of unsatisfied performance obligations are not disclosed for (1) contracts with an original expected length of one year or less, (2) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (3) contracts with variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (4) contracts that were not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.
Income Taxes	Income Taxes The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company follows the “equity first” approach when applying the limitation for certain executive compensation in excess of $1 million to future compensation. The limitation is first applied to stock-based compensation that vests in future tax years before considering cash compensation paid in a future period. Accordingly, the Company records a deferred tax asset for stock-based compensation expense recorded in the current period, and reverses the temporary difference in the future period, during which the stock-based compensation becomes deductible for tax purposes. The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties. The Company recognizes accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the Consolidated Statement of Operations.
Stock-Based Compensation	Stock-Based Compensation The Company accounts for stock-based compensation under the fair value method of accounting. Under this method, compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, the Company uses a Black Scholes or Monte Carlo valuation model based on the specific provisions of the award. Stock-based compensation cost for all types of awards is included in general and administrative expense in the Consolidated Statement of Operations. The Company records excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Excess tax benefits and tax deficiencies are included in cash flows from operating activities in the Consolidated Statement of Cash Flow. Cash paid by the Company when directly withholding shares from employee stock-based compensation awards for tax-withholding purposes are classified as financing activities in the Consolidated Statement of Cash Flow.
Earnings per Share	Earnings per Share The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the Company’s unvested share-based payment awards, consisting of restricted stock, qualify as participating securities. The Company’s participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them.
Environmental Matters	Environmental Matters Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
Credit and Concentration Risk	Credit and Concentration Risk Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and NGLs to third parties in the oil and gas industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties. During the year ended December 31, 2021, no customer accounted for more than 10 percent of the Company’s total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 percent of the Company's total sales. During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on it because alternative customers are readily available. If any one of the Company’s major customers were to stop purchasing the Company’s production, the Company believes there are a number of other purchasers to whom it could sell its production. If multiple significant customers were to stop purchasing the Company’s production, the Company believes there could be some initial challenges, but the Company believes it has ample alternative markets to handle any sales disruptions. The Company regularly monitors the creditworthiness of its customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have been insignificant.
Use of Estimates	Use of Estimates In preparing financial statements, the Company follows GAAP. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization, impairments of proved oil and gas properties and the fair value of oil and gas properties in purchase accounting. Other estimates include oil, natural gas and NGLs revenues and expenses, fair value of derivative instruments, estimates of expenses related to legal, environmental and other contingencies, asset retirement obligations, postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Nature of Operations

Coterra Energy Inc. and its subsidiaries (“Coterra” or the “Company”) are engaged in the development, exploration and production of oil, natural gas and NGLs exclusively within the continental U.S. The Company's exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

The Company operates in one segment, oil and natural gas development, exploration and production. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company's entire portfolio without regard to geographic areas.

The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders' equity, net income or cash flows.

The Company (formerly known as Cabot Oil & Gas Corporation) and Cimarex Energy Co. (“Cimarex”) completed a merger transaction on October 1, 2021 (the “Merger”), pursuant to an agreement entered into by the Company and Cimarex (the “Merger Agreement”). Upon the effectiveness of the Merger, each eligible share of Cimarex common stock was automatically converted into the right to receive 4.0146 shares of the Company’s common stock. The transaction has been accounted for using the acquisition method of accounting, with the Company being treated as the accounting acquirer. Refer to Note 2, “Acquisitions,” for further information. Additionally, on October 1, 2021, Cabot Oil & Gas Corporation changed its name to Coterra Energy Inc.

Recently Issued and Adopted Accounting Pronouncements

Convertible Instruments. In August 2020, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity ("ASU 2020-06"), which simplifies the accounting for convertible instruments by removing the separation models for (1) convertible debt with a cash conversion feature and (2) convertible instruments with a beneficial conversion feature. As a result, a convertible debt instrument will be accounted for as a single liability measured at its amortized cost. ASU 2020-06 also requires the application of the if-converted method for calculating diluted earnings per share for all convertible instruments and the treasury stock method will no longer be available. For public companies, the guidance is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. Early adoption is permitted in the first quarter of 2021. The Company elected to adopt the guidance in ASU 2020-06 as of October 1, 2021. The adoption of ASU 2020-06 did not have any effect on the Company’s financial positions, results of operations or cash flows; however, it modified certain disclosures, which were not material.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in four financial institutions at December 31, 2021. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal.

From time to time, the Company may be in the position of a book overdraft in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable in the Consolidated Balance Sheet, and classifies the change in accounts payable associated with book overdrafts as an operating activity in the Consolidated Statement of Cash Flows. There was no book overdraft within accounts payable as of December 31, 2021 and 2020.

Restricted Cash

Restricted Cash Restricted cash includes cash that is legally or contractually restricted as to withdrawal or usage. As of December 31, 2021 and 2020, the restricted cash balance of $10 million and $12 million, respectively, includes cash deposited in escrow accounts that are restricted for use.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts based on the Company's estimate of future expected credit losses on outstanding receivables.

Inventories

Inventories are comprised of tubular goods and well equipment and are carried at average cost. Inventories are assessed periodically for obsolescence.

Properties and Equipment

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the Consolidated Statement of Operations in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether reserves have been found only as long as: (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively.

Costs of sold or abandoned properties that make up a part of an amortization base (partial field) remain in the amortization base if the units-of-production rate is not significantly affected. If significant, a gain or loss, if any, is recognized and the sold or abandoned properties are retired. A gain or loss, if any, is also recognized when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

The Company evaluates its proved oil and gas properties for impairment whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to the Company's undeveloped acreage amortization based on past drilling and exploration experience, the Company's expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

Fixed Assets

Fixed assets consist primarily of gas gathering systems, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the units-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in depreciation, depletion and amortization expense in the Consolidated Statement of Operations.

Derivative Instruments

The Company enters into financial derivative contracts, primarily collars, swaps, roll differential swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future production volumes. The Company’s credit agreement restricts the ability of the Company to enter into financial commodity derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. The Company has elected not to designate its financial derivative instruments as accounting hedges under the accounting guidance.

The Company evaluates all of its physical purchase and sale contracts to determine if they meet the definition of a derivative. For contracts that meet the definition of a derivative, the Company may elect the normal purchase normal sale (“NPNS”) exception provided under the applicable accounting guidance and account for the contract using the accrual method of accounting. Contracts that do not qualify for or for which the Company elects not to apply the NPNS exception are accounted for at fair value.

All derivatives, except for derivatives that qualify for the NPNS exception, are recognized on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked to market. As a result, changes in the fair value of derivatives are recognized in operating revenues in gain (loss) on derivative instruments. The resulting cash flows are reported as cash flows from operating activities.

Leases

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in operating lease right-of-use assets (“ROU assets”) and operating and financing lease liabilities (current and non-current) in the Consolidated Balance Sheet.

ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company uses its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities.

The Company has elected the following practical expedients in applying authoritative guidance on lease accounting:

•For all operating leases, lease and non-lease components are accounted for as a single lease component.

•Short-term leases (a lease that, at commencement, has a lease term of one year or less and does not contain a purchase option that the Company is reasonably certain to exercise) are not recognized in ROU assets and lease liabilities.

•Certain land easements in existence prior to January 1, 2019 were not reassessed under new accounting guidance.

Fair Value of Assets and Liabilities

The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows:

•Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets.

•Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability.

•Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment.

The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in the valuation should be chosen.

Revenue Recognition

The Company’s revenue is typically generated from contracts to sell oil, natural gas and NGLs produced from interests in oil and gas properties owned by the Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that is either fixed or variable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. These contracts frequently meet the definition of a derivative under Accounting Standards Codification (“ASC”) 815, and are accounted for as derivatives unless the Company elects to treat them as normal sales as permitted under that guidance. The Company typically elects to treat contracts to sell oil, natural gas and NGL production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred.

Gain or loss on derivative instruments is outside the scope of the revenue recognition standard and is not considered revenue from contracts with customers under that guidance. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue.

Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. Under this method, a natural gas imbalance liability is recorded if the Company's excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties at the actual price realized upon the gas sale. A receivable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2021 and 2020 were not material.

Practical Expedients. The Company makes use of certain practical expedients provided under the revenue standard, including the value of unsatisfied performance obligations are not disclosed for (1) contracts with an original expected length of one year or less, (2) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (3) contracts with variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (4) contracts that were not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company follows the “equity first” approach when applying the limitation for certain executive compensation in excess of $1 million to future compensation. The limitation is first applied to stock-based compensation that vests in future tax years before considering cash compensation paid in a future period. Accordingly, the Company records a deferred tax asset for stock-based compensation expense recorded in the current period, and reverses the temporary difference in the future period, during which the stock-based compensation becomes deductible for tax purposes.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties.

The Company recognizes accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the Consolidated Statement of Operations.

Stock-Based Compensation

The Company accounts for stock-based compensation under the fair value method of accounting. Under this method, compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, the Company uses a Black Scholes or Monte Carlo valuation model based on the specific provisions of the award. Stock-based compensation cost for all types of awards is included in general and administrative expense in the Consolidated Statement of Operations.

The Company records excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Excess tax benefits and tax deficiencies are included in cash flows from operating activities in the Consolidated Statement of Cash Flow.

Cash paid by the Company when directly withholding shares from employee stock-based compensation awards for tax-withholding purposes are classified as financing activities in the Consolidated Statement of Cash Flow.

Earnings per Share

The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the Company’s unvested share-based payment awards, consisting of restricted stock, qualify as participating securities. The Company’s participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Credit and Concentration Risk

Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and NGLs to third parties in the oil and gas industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

During the year ended December 31, 2021, no customer accounted for more than 10 percent of the Company’s total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 percent of the Company's total sales. During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on it because alternative customers are readily available. If any one of the Company’s major customers were to stop purchasing the Company’s production, the Company believes there are a number of other purchasers to whom it could sell its production. If multiple significant customers were to stop purchasing the Company’s production, the Company believes there could be some initial challenges, but the Company believes it has ample alternative markets to handle any sales disruptions.

The Company regularly monitors the creditworthiness of its customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have been insignificant.

Use of Estimates

In preparing financial statements, the Company follows GAAP. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization, impairments of proved oil and gas properties and the fair value of oil and gas properties in purchase accounting. Other estimates include oil, natural gas and NGLs revenues and expenses, fair value of derivative instruments, estimates of expenses related to legal, environmental and other contingencies, asset retirement obligations, postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.