Summary of Significant Accounting Policies	12 Months Ended
Dec. 31, 2022
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3 – Summary of Significant Accounting Policies Principles of Consolidation In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries. The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant. The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects the noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying consolidated financial statements and represents the ownership interest held by Juniper in the Partnership (the “Noncontrolling interest”). Noncontrolling interest The Noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of December 31, 2022, the Company owned 19,074,864 Common Units, representing a 45.8% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.2% limited partner interest. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the year ended December 31, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 15 for information regarding share repurchases and Note 16 for vesting of share-based compensation. When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification (“ASC”) Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the Class A common shareholders and the Noncontrolling interest pro rata based on ownership interests in the Partnership. Use of Estimates Preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Some of our account balances exceed the FDIC coverage limits. We believe our cash and cash equivalents are not subject to any material interest rate risk, equity price risk, credit risk or other market risk. Derivative Instruments We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors. All derivative instruments are recognized in our consolidated financial statements at fair value. We have elected to report all of our derivative asset and liability positions on a gross basis on our consolidated balance sheets and not net the positions, even when a legal right-of-setoff exists. Our derivative instruments are not formally designated as hedges in the context of GAAP. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. We recognize changes in fair value in income within Derivatives gains (losses) in our consolidated statements of operations. See Note 6 for further information on our derivatives. Inventory Inventory is stated at the lower of cost and net realizable value using the average cost method. Our inventory consists of tubular goods and equipment that are primarily comprised of oil and natural gas drilling and repair items such as tubing, casing and pumping units. Property and Equipment Oil and Gas Properties We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”). Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. Other Property and Equipment Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three to 20 years. Leases We determine if a contractual arrangement is a lease at inception and whether it is classified as operating or financing 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. Leases are included in Other assets, Accounts payable and accrued liabilities and Other liabilities on our consolidated balance sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Note 11 and Note 12. ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to five years, our secured incremental borrowing rate is primarily based on the rates applicable to our Credit Facility. We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We apply a practical expedient provided in Accounting Standards Codification (“ASC”) Topic 842, Leases, to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term. Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases and are recognized on a straight-line basis over the lease term. Accordingly, we do not include the underlying ROU assets and lease obligations on our consolidated balance sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11. Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11. Asset Retirement Obligations We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our consolidated statements of operations. Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent it may be incurred, as a component of interest expense and penalties as a component of income tax expense. We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain. Revenue Recognition and Associated Costs The Company recognizes revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers, which includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. See Note 5 for further discussion. Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create material contract assets or liabilities. Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation expense (“GPT”) in our consolidated financial statements. NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue. Natural gas. Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’ facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses in our consolidated financial statements. Marketing and water disposal services. We provide marketing and water disposal services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in General and administrative expenses (“G&A”) and direct costs associated with our water service efforts are netted against the underlying revenue. Credit Losses We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10% in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10% in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable. Share-Based Compensation Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period. Awards that are based on performance are amortized either on a graded basis over the term of the applicable performance periods for awards that represent in-substance multiple awards or ratably over the requisite service period for awards that cliff vest. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A expenses in our consolidated statements of operations. Recent Accounting Pronouncements We consider the applicability and impact of all Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to be not applicable. Recently Issued Accounting Pronouncements Not Yet Adopted In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.

In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant.

The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects the noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying consolidated financial statements and represents the ownership interest held by Juniper in the Partnership (the “Noncontrolling interest”).

The Noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of December 31, 2022, the Company owned 19,074,864 Common Units, representing a 45.8% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.2% limited partner interest. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the year ended December 31, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 15 for information regarding share repurchases and Note 16 for vesting of share-based compensation.

When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification (“ASC”) Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the Class A common shareholders and the Noncontrolling interest pro rata based on ownership interests in the Partnership.

Preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates.

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Some of our account balances exceed the FDIC coverage limits. We believe our cash and cash equivalents are not subject to any material interest rate risk, equity price risk, credit risk or other market risk.

We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.

All derivative instruments are recognized in our consolidated financial statements at fair value. We have elected to report all of our derivative asset and liability positions on a gross basis on our consolidated balance sheets and not net the positions, even when a legal right-of-setoff exists. Our derivative instruments are not formally designated as hedges in the context of GAAP. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. We recognize changes in fair value in income within Derivatives gains (losses) in our consolidated statements of operations. See Note 6 for further information on our derivatives.

We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”).

Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.

Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three to 20 years.

We determine if a contractual arrangement is a lease at inception and whether it is classified as operating or financing 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. Leases are included in Other assets, Accounts payable and accrued liabilities and Other liabilities on our consolidated balance sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Note 11 and Note 12.

ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to five years, our secured incremental borrowing rate is primarily based on the rates applicable to our Credit Facility.

We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We apply a practical expedient provided in Accounting Standards Codification (“ASC”) Topic 842, Leases, to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term.

Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases and are recognized on a straight-line basis over the lease term. Accordingly, we do not include the underlying ROU assets and lease obligations on our consolidated balance sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11.

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our consolidated statements of operations.

We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent it may be incurred, as a component of interest expense and penalties as a component of income tax expense.

We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.

The Company recognizes revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers, which includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. See Note 5 for further discussion.

Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create material contract assets or liabilities.

Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation expense (“GPT”) in our consolidated financial statements.

NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue.

Natural gas. Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’ facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses in our consolidated financial statements.

Marketing and water disposal services. We provide marketing and water disposal services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in General and administrative expenses (“G&A”) and direct costs associated with our water service efforts are netted against the underlying revenue.

We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10% in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10% in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable.

Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period. Awards that are based on performance are amortized either on a graded basis over the term of the applicable performance periods for awards that represent in-substance multiple awards or ratably over the requisite service period for awards that cliff vest. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A expenses in our consolidated statements of operations.

In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.